Apparatus and method using measurements taken while drilling to map mechanical boundaries and mechanical rock properties along a borehole

ABSTRACT

An apparatus and method of using drilling vibrations generated by the deformation of a rock formation in response to forces acting on the rock formation, where the forces are related to a drill bit and/or drilling fluid system, to identify the nature and occurrence of fractures, fracture swarms and other mechanical discontinuities (boundaries) such as bedding planes and/or faults that offset or otherwise separate rock formations with different mechanical rock properties.

RELATED APPLICATIONS

This application claims priority under 35 U.S.C. § 119 from U.S.provisional application No. 62/048,669 entitled “APPARATUS AND METHODUSING MEASUREMENTS TAKEN WHILE DRILLING TO MAP MECHANICAL BOUNDARIES ANDMECHANICAL ROCK PROPERTIES ALONG A BOREHOLE,” filed on Sep. 10, 2014,the entire contents of which are fully incorporated by reference hereinfor all purposes.

TECHNICAL FIELD

The present disclosure involves measurement while drilling techniquesthat provide mechanical rock properties, and from which fractures andother mechanical boundaries may be identified and used to improvedrilling and completion practices, among other things.

BACKGROUND

The production of hydrocarbons (oil or gas) can be generally distilledinto two primary steps—drilling a borehole to intersect hydrocarbonbearing formations or oil and gas reservoirs in the subsurface, and thencompleting the well in order to flow the hydrocarbons back to thesurface. The ability of a well to flow hydrocarbons that arecommercially significant requires that the borehole be connected to oiland gas bearing formations with sufficient permeability to support theflow rates that are needed to account for the costs of developing thefield. In many instances, however, commercially viable flow rates cannotbe obtained without the use of various advancements including horizontaldrilling and hydraulic stimulation due to the type of formation orreservoir being developed.

More specifically, unconventional resource plays are areas wheresignificant volumes of hydrocarbons are held in reservoirs with lowprimary permeability (nanodarcy to microdarcy) and low primary porosity(2-15%) such as shales, chalks, marls, and cemented sandstones thatgenerally do not have sufficient primary permeability to yieldcommercial quantities of hydrocarbons. Compared to “conventional”reservoirs, unconventional reservoirs have a much lower hydrocarbondensity per unit volume of rock and much lower unstimulated hydrocarbonflow rates, making commercial development impossible without hydraulicstimulation of the reservoir rock fabric. Fortunately, unconventionalreservoirs are often regionally extensive covering thousands of squaremiles and containing billions of barrel of oil equivalent (BOE) ofpotentially recoverable hydrocarbons.

The economically viable production from unconventional resources hasonly been made possible by the improvement and combination of horizontaldrilling, wellbore isolation, and hydraulic fracture stimulationtreatment technologies, among other techniques. Generally speaking,horizontal drilling involves first vertically drilling down close to thetop of the unconventional reservoir and then using directional drillingtools to change the orientation of the wellbore from vertical tohorizontal in order to contact greater areas of the reservoir per well.The term “horizontal” drilling as used herein is meant to refer to anyform of directional (non-vertical) drilling. Horizontal drilling,although having been performed for many decades prior to intensiveunconventional resource development in the early 2000's, has beenevolved to provide cost effective provisioning of the long horizontalborehole sections (5,000′ to 10,000+′) required to contact commerciallyviable volumes of hydrocarbon bearing reservoir rock. Hydraulic fracturestimulation involves pumping high volumes of pressurized fluid into theborehole and through targeted perforations in the wellbore to createlarge networks of cracks (fractures) in the formation that createenhanced reservoir permeability and so stimulate greater quantities ofoil and gas production. Proppant is usually pumped along with the fluidto fill the fractures so permeability is maintained after the pumping isstopped and the fractures close due to reservoir stresses. Proppant canrange from simple quarried sand to engineered man-made materials.

Isolation generally involves the use of some form to technology to focuswhere fracturing occurs at specific locations along the well bore ratherthan stimulating the entire length of an open wellbore. In thedevelopment of unconventional resources it is desirable to drillhorizontal wells perpendicular to the direction of maximum horizontalcompressive stress, because hydraulically induced fractures will growprimarily in the direction of maximum horizontal stress. When thewellbore is oriented perpendicular to the maximum horizontal compressivestress, this geometry allows for the shortest, and hence leastexpensive, well bore length for the volume of reservoir stimulated.

Rapidly evolving wellbore isolations techniques, such as swellablepackers, sliding sleeves, and perforation cluster diversion have allassisted in reducing the cost of isolating sections of the wellbore formore targeted and more concentrated hydraulic stimulation. Hydraulicfracture stimulation has been utilized on low permeability wells fordecades as well. But the use of low viscosity, simple fluids pumped invery high volumes and rates, and with large volumes of associatedproppant, has been the most important aspect of contacting the greatestamount of low permeability, low hydrocarbon density reservoir rock.

Various suites of drill string or wireline conveyed well logs such asdipole sonic or natural fracture image logs can identify and quantifythis variability on a scale that is useful to completions design, butexisting tools are currently too expensive to run on anything but a verysmall fraction of unconventional wells drilled. Conventional techniques,such as dipole sonic and natural fracture image logs, are based oninferred information and not involved directly measuring the interactionof the drill bit with the formation. Instead, dipole sonic involves thetransmission of acoustic signals (waves) from a controlled activeacoustic source, through the rock formation in the areas of the wellbore to a receiver typically several feet from the source, to measurethe velocity of the waves through the formation. Natural fracture imagelogs involve measuring the resistivity of the formation along the wallsof the wellbore. Natural fracture logs are of limited use in wells usingoil based mud, which has an inherently high resistivity and masks somefractures. These techniques are often cost prohibitive and limited ineffectiveness. As a result, almost all wells are completed usinggeometrically equal spacing of zones isolated (referred to as stages)and stimulated. Thus, for example, hydraulic fracturing is inadvertentlyperformed routinely on individual stages with significantly varying rockproperties along the isolated section, resulting in the failure toinitiate induced fractures in less conducive rock and so potentiallybypassing substantial volumes of hydrocarbon bearing rock. In suchinstances, post stimulation testing of individual zones or stages showsthat a significant percentage of the hydraulically stimulated zones arenot contributing to hydrocarbon production from the well. Variations inthe density, size and orientation of natural fractures can have a majorinfluence on overall well initial production, long term decline rates,and stage to stage contributions. Formation hydrocarbons are transportedfrom the rock matrix to the producing wellbore through some combinationof induced hydraulic fractures and natural occurring in-situ fractures.

Currently, less than 1% of all wells drilled and completed have suitabledata to adequately quantify reservoir heterogeneity on a scale that canbe used for targeting individual stimulation intervals.

It is with these observations in mind, among others, that aspects of thepresent disclosure have been conceived and developed.

SUMMARY

Aspects of the present disclosure involve a method of characterizingrock properties while drilling comprising: receiving acoustical signalsobtained from one or more sensors positioned on a component of a bottomhole assembly where the sensors (e.g., accelerometers or strain gauges)are in operable communication with at least one data memory to store theacoustical signals. The acoustical signals, which may also be consideredvibrations, are generated from a drill bit interacting with a rockformation while drilling a wellbore. The method further involvesprocessing the acoustical signals to obtain at least one set of datavalues representative of a mechanical rock property of the rockformation along the wellbore created by the drill bit interacting withthe rock formation for a period of time. The method may further involveidentifying a change in the at least one set of data values where thechange representative of the drill bit crossing a mechanical rockproperty discontinuity while drilling the wellbore.

Another aspect of the present disclosure involves a method of completinga well that involves receiving a well log spatially identifying aplurality of mechanical discontinuities in a horizontal wellbore wherethe plurality of mechanical discontinuities are indicative of arespective plurality of preexisting fractures along the horizontalwellbore, and the well log is generated from a data set recorded at adown hole assembly and where the data is related to a drill bitinteracting with a rock formation while drilling the horizontalwellbore. The method may further involve completing (e.g., hydraulicallyfracturing) the horizontal wellbore based on the plurality of mechanicaldiscontinuities indicative of the respective plurality of preexistingfractures.

Yet another aspect involve a method of characterizing rock propertieswhile drilling that involves receiving dynamic drilling data associatedwith a bottom hole assembly including a drill bit interacting with arock formation while drilling. The process further involves processingthe dynamic drilling data to obtain at least one set of data valuesrepresentative of a mechanical rock property of the rock formation alonga wellbore created by the drill bit interacting with the rock formationfor a period of time, and identifying a change in the at least one setof data values where the change is representative of the drill bitcrossing a mechanical rock property discontinuity while drilling thewellbore.

Another aspect involves a method, using at least one processing unit incommunication with a tangible storage media having acceleration datarelating to at least one of lateral or rotary and axial drill vibrationobtained while drilling a well bore through a formation, computing afirst curve of a first elastic coefficient of the formation proximatethe well bore assuming an axis of material symmetry of the formation isparallel to an axis of direction of drilling the well bore, where thefirst curve provides a first set of values of the first elasticcoefficient along a length of a well bore. The method further involvescomputing a second curve of a second elastic coefficient of theformation proximate the well bore assuming an axis of material symmetryof the formation is perpendicular to the axis of direction of drillingthe well bore, the second curve provides a second set of values of thesecond elastic coefficient along the length of well bore. Finally, themethod involves obtaining a difference between the first curve and thesecond curve to identify a mechanical discontinuity in the formationalong the length of the well bore.

These and other aspects are disclosed in further detail in thedescription set out below.

BRIEF DESCRIPTION OF THE FIGURES

FIGS. 1A-1B Illustrate reservoir-to-well connectivity where brittlerocks are generally associated with larger fracture creation and betterproppant support that is more permeable than ductile rock that producessmaller, less productive fractures which are prone to rapid compactionand closure and are less permeable.

FIG. 2 is a diagram of a drill bit assembly including sensors formeasuring bit accelerations and forces on the bit, and which includes atleast one processing unit and tangible storage media in which to storeacceleration and/or force data, and which may also store processedacceleration and/or force data of the drill bits interaction with aformation while drilling.

FIGS. 3A-3C illustrate the cutting action of a drill bit, stick slipfracturing of a rock formation, torque on bit and weigh on bit forces,and related torque and displacement curves.

FIG. 4 illustrates root mean square computations for axial accelerationof the bit as used in computing rock properties.

FIG. 5A is a rotary displacement spectra obtained from measurement whiledrilling data;

FIG. 5B is a diagram illustrating lateral and rotary acceleration of thebit, while cutting, and useful in computing mechanical rock propertiesamong other advantages;

FIG. 6 is a diagram illustrating drill bit behaviour when encountering amechanical discontinuity or geological boundary, the cutting face of thedrill bit may change its orientation, as detectable from accelerationdata, in response to the orientation and stresses acting on theheterogeneity.

FIG. 7 is a graph of rock strength curves computed from torque andpenetration per revolution information based on measurement whiledrilling data.

FIG. 8A illustrates stress strain relationships based on an orientationof a well relative to a transverse isotropic axis of material symmetryand mechanisms whereby measurement while drilling techniques may be usedto compute elastic coefficients, from which temporal and/or spatialvariations in one or a combination of more of the measurements obtainedfrom the geophysical signal processing techniques are used to identifythe nature and occurrence of fractures, fracture swarms and othermechanical discontinuities (boundaries) such as bedding planes and/orfaults that offset or otherwise separate rock formations with differentmechanical rock properties.

FIG. 8B is a stress strain curve reflecting the relationships of FIG.8A.

FIG. 9A illustrates a constitutive stress strain relationship for anaxis of material symmetry parallel a well axis, and computations usingtorque on bit, weigh on bit and axial displacement to obtain elasticcoefficients from measurement of bit vibration and/or forces acting onthe bit.

FIG. 9B illustrates a constitutive stress strain relationship for anaxis of material symmetry perpendicular a well axis, and computationsusing torque on bit, weigh on bit and rotary displacement to obtainelastic coefficients from measurement of bit vibration and/or forcesacting on the bit.

FIGS. 10A-10C a constitutive stress strain relationships for an axis ofmaterial parallel and perpendicular a well axis, using accelerationdata.

FIG. 11 illustrates constitutive stress strain relationships for an axisof material symmetry parallel a well axis and axis of symmetryperpendicular a well axis, with Poisson's ratio and Young's Modulus ofElasticity computed from measurement while drilling data of torque onbit, weigh on bit, and acceleration data to obtain lateral and axialdisplacement.

FIG. 12 illustrates stress strain curves obtained by the methodsdiscussed herein.

FIG. 13 illustrates two relative curves of Poisson's ratio for avertical well, with cross over points identifying likely preexistingfractures in the fracture detection log.

FIG. 14A illustrates two relative curves of Young's Modulus ofElasticity for a horizontal well, and 14B illustrates two relativecurves of Poisson's ratio for the same horizontal well, with cross overpoints identifying mechanical rock properties indicative of preexistingfractures.

FIG. 15 If the forces acting on the formation in connection with thedrill bit and drilling fluid system when conducting drilling operationsare sufficient to overcome the failure criteria of a pre-existing fault,then the fault will slip or fail. Reactivation of a fault orpre-existing fracture can be evidenced by extracting a signal from thedrilling vibrations that is related to a microseismic event withattendant primary, compressional (P) and secondary, or shear (S)arrivals. In the case where the fault is perpendicular to the trajectoryof the wellbore the P-wave arrival is related the particle motionparallel to the axis of the drill string and the S- or transverse waveis the particle motion parallel to the lateral and torsional motion ofthe drill string. Deviations of the particle motion of the P- andS-waves relative to the orientation of the well can be used to determinethe orientation of the fault.

FIG. 16 is a method of obtaining mechanical rock properties of aformation proximate a well bore from measurements of bit behavior takenwhile drilling.

FIG. 17 is a special purpose computer programmed with instructions toexecute methods discussed herein.

DETAILED DESCRIPTION

The present disclosure involves a novel way of using drilling vibrationsgenerated by the deformation of a rock formation in response to forcesacting on the rock formation, where the forces are related to a drillbit and drilling fluid system, to identify the nature and occurrence offractures, fracture swarms and other mechanical discontinuities(boundaries) such as bedding planes and/or faults that offset orotherwise separate rock formations with different mechanical rockproperties.

The techniques and measurements from this disclosure are made usingdownhole tools that are simple and rugged, allowing for a magnitude inorder reduction in logging cost to characterize near-wellbore rockmechanical properties and intersected existing fracture locations. Thelow cost to log a well, typically less 0.5% of the total well cost,allows for widespread use of the technique. Detailed knowledge of rockproperty variability along a wellbore allows for grouping like-for-likerock types in variable length stages, avoiding losing reserves due to alack of fracture initiation relative to mixed rock strength stages.Also, knowledge of existing fractures will improve well economicsoverall as fractures can be targeted for stimulation to improve initialproduction if appropriate, or avoided for example when setting swellpacker locations.

Further elaboration of the method describes how mechanical rockproperties, and in particular elastic coefficients of a rock formation,can be determined through the application and use of innovative, newstress-strain relationships that systematically relate measurements ofthe forces acting on rock formation in connection with the drill bit anddrilling fluid system (stress) to the variations in the drillingvibrations generated by the deformation of the rock formation inresponse to the cutting action of the bit (strain).

The elastic coefficients can be used, in general to describe thedeformation of a rock formation in response to the forces acting on therock formation, and in particular, to predict the deformation of ahydrocarbon bearing formation in response to the forces acting on theformation where the forces are fluid pressures generated during theemplacement of hydraulic fractures in connection with a hydraulicfracture stimulation treatment along a horizontal well.

The processing of drilling vibrations when recorded using sensorsdeployed in a borehole in connection with a bottom hole assembly (BHA)according to the method disclosed here, can provide measurements ofmechanical rock properties including the nature and occurrence ofmechanical discontinuities, such as pre-existing fractures, which can beused to target sections of the well where the rock properties areconducive to economical hydraulic stimulation and to avoid sections thatare viewed as sub-commercial, where the rock properties are notconducive to economical hydraulic stimulation.

In another embodiment of the method, the elastic coefficients andvariations in the elastic coefficients that are obtained whileconducting drilling operations can be used for assisting, in real-time,the steering of the bottom hole assembly in order to maintain thetracking of the drill bit through geological formations as are targetedaccording to the desired mechanical rock properties, especially wherethe mechanical rock properties are relevant to the production ofcommercially significant hydrocarbons using hydraulic fracturingstimulation techniques.

The present disclosure generally relates to the production ofcommercially significant hydrocarbons from oilfield drilling operationsand completion operations. Recent unconventional resource developmenthas identified a need for economical determination of rock propertiesand natural fracture swarm locations along a horizontal well in order tooptimize the location and intensity of hydraulic stimulation treatments.

The techniques described in this disclosure will provide new informationfor selecting hydrocarbon bearing zones by differentiating betweenbrittle rocks generally associated with larger fracture creation andbetter proppant support that is more permeable than ductile rock thatproduces smaller, less productive fractures which are prone to rapidcompaction and closure and are less permeable. Natural fractureidentification also refines the process of hydraulic stimulationoptimization by providing direct measurement of zones that offer higherpermeability and higher hydrocarbon productivity.

Physical Basis of the Method

Aspects of the present disclosure involve methodologies that use broadband measurements (e.g., continuous, high resolution) of drillingvibrations and drilling dynamics data taken proximate the drill whileconducting drilling operations bit to log the mechanical properties of arock formation.

Drilling vibrations generated by the deformation and failure of a rockformation are generally related to the mechanical properties of the rockbeing drilled. It is generally understood that the depth of cut or thetooth penetration into the rock is inversely related to the strength ofthe rock. Higher amplitude drilling vibrations occur in rocks thatundergo a greater depth of cut and deeper tooth penetration in responseto the forces acting on the formation in connection with the drill bitand drilling fluid system, whereas lower amplitude drilling vibrationsoccur in rocks that undergo relatively lower depth of cut and lessertooth penetration. Increased depth of cut indicate the bit is movinginto an area of lesser relative mechanical rock strength, and decreasedrelative drilling vibrations indicate the bit is moving into an area ofgreater relative rock strength all other things being equal.

Generally speaking, rock formations that take a relatively long time todrill through or where the rate of penetration is slow are generallyreferred to strong or hard formations and have a lesser depth of cut inrelation to rock formations that are relatively weaker and less rigid.These basic principles have enabled the application and use oftechniques that take measurements of the hardness of a rock formation byforcing a tool into a rock to make an indentation where the depth of theindentation relative to the force applied is used to obtain a hardnesscharacteristic that is essentially a mechanical property of a rockformation.

The presence of mechanical discontinuities, such as pre-existingfractures, and geological boundaries, such as faults, in a rockformation generally act to weaken the rock formation. Fractured rockformations, are generally weaker and less rigid than intact, unfracturedor stiff or otherwise competent rock formations. As the drill bitencounters fractures in a rock formation the tooth penetration or depthof cut and subsequently the drilling vibrations will increase, becausethe rock formation is less rigid because it has been weakened by thepresence of fractures. Stated differently, as the drill moves into andthrough existing fractures, the measured mechanical rock strength willdecrease relative to the same rock formation without a fracture or withlesser fractures, for example.

General Description of Fracture Identification in Relation to the Method

Signal processing techniques are used to process the drilling data toidentify locations where the changes in the drilling vibration indicatethat the drill bit has encountered a mechanical discontinuity orgeological boundary. If the changes in the drilling vibration asexpressed through the results of the geophysical signal processingtechniques are rapid and discrete in both space and time, and thenreturn back to a long-term trend or the levels that were recorded priorto the change in the drilling vibrations, then it would indicate thatthat the drill bit has encountered and crossed a discrete mechanicaldiscontinuity because mechanical rock properties that are discrete inboth space and time are uniquely separated from the mechanicalproperties of a rock formation such as would be in the case of a drillbit penetrating a fracture face. If the changes in drilling vibrationare rapid and discrete and continue over a short interval, then thatwould indicate multiple fractures or a swarm of fractures has beenencountered.

If the signal processing techniques indicate that the changes in thedrilling vibration are rapid, but then do not revert back to the levelprior to the change and instead carry on at a new, significantlydifferent level, then that indicates a mechanical boundary where themechanical boundary that separates or offsets two different rockformations such as a bedding plane and or fault has been encountered andcrossed. Whether or not the boundary is related to a fault or a beddingplane depends on the inclination of the bit with respect to theorientation of the stratigraphy of the rock formation being drilled.Other information may also be used to determine whether or not themechanical boundary was a bedding-plane fault or bedding plane thatacted as a zone of weakness that had experienced measurable displacementin the past.

The description provides a method to evidence the presence of fractures,fracture swarms and other mechanical discontinuities such as faults andbedding planes that offset or otherwise separate rock formations withdifferent rock properties. The approach uses geophysical signalprocessing techniques that are sensitive to changes in the drillingvibrations where the changes are relative to some baseline, such as anormalized preceding set of drilling vibration data, and whether or notthe changes are discrete and then return back to the level prior to thechange or are maintained at a new level that is different than the levelobserved prior to the change.

The following method disclosed below further elaborates on the outlinedprinciples to provide a general, independent method to specify themechanical properties of a rock formation by processing the drillingvibrations in relation to the forces acting on the formation inconnection with a drill bit and, in some instances, a drilling fluidsystem, which includes the mud motor and the drilling fluid, includingmud, that turns the motor. This method specifies the mechanicalproperties of a rock formation through the application and use ofinnovative, new stress-strain relationships, among other advances.

Because the cutting depth or the penetration of the bit tooth into theformation is a measurement of displacement, the drilling vibrationsdescribe the strain experienced by a rock formation in response to thecutting action of the bit where greater cutting depths and a greaterpenetration of the bit tooth relative to the same volume of rock resultin a higher strain. Strain is understood to describe a change in volumeof a rock under some force. In some aspects, strain is reflected byaxial displacement of the bit per turn of the bit. In one example, axialdisplacement is computed as a double integral of the accelerometer data(axial) for one revolution of the bit to yield a distance measurementfor one revolution (or some other known number of turns). If this strainis calculated with respect to time, then the drilling vibrations can beused to describe the strain rate. The converse with regards to thestrain and the rate of strain is also held to be evident.

Through the techniques described herein, the drilling vibrationcharacteristics, which may be supplemented with drilling dynamics dataincluding forces on the bit, such as torque on bit and weight on bit,are translated into mechanical properties of a rock formation. The depthof cut, as obtained based on vibration assessment, may be normalizedagainst direct weight on bit and/or torque on bit measurements, orweight on bit or torque on bit measurements extrapolated from vibrationinformation.

General Stress-Strain Relationships

Stress-strain relationships are established by systematically relatingforces acting on the formation in connection with the drill bit anddrilling fluid system to the geophysical signal processing of drillingvibrations generated by the deformation of the rock in response to thecutting action of the bit. This approach allows elastic coefficients (K)to be derived in accordance with the following equation where (e) is thegeneral deformation (strain) of a rock formation in response to theforces acting on a rock formation (S) (stress).S=Ke

In accordance with some methods set out herein, strain (the motion ordisplacement of the bit is obtained by signal processing the drillingvibrations as are transmitted along the drilling assembly by sensorsdeployed in a borehole in connection with a BHA. Stress, in accordancewith some methods set out herein, is obtained from either (i) downholeor (ii) surface measurements of torque and/or weight on bit, or (iii) inanother example, the accelerations of the bit are related to forces onbit where it understood that the acceleration is a representation offorce per unit mass. It should be appreciated that forces can beconverted to stresses with knowledge of the effective contact area ofthe bit and formation, and the effective rock volume the bit is actingon. Conversely, forces can be substituted for stresses with theunderstanding that a geometric correction in relation to the effectivecontact area is required to obtain absolute values for the mechanicalrock properties. One example of such a contact area is the area of thebit.

The equations of linear elasticity are useful for describing therelationship between the changes in shape and position of a material inrelation to the forces acting on the material. Such stress-strainrelationships are known in general as Hooke's law where the coupling ofthe stress-strain relationship behavior is described through a matrix ofcoefficients whose values depend on the conditions used to load thematerial in relation to the structural symmetry of the material beingloaded. These coefficients are colloquially known as the cij's and canbe arranged in well-known and convenient forms to represent Young'sModulus of Elasticity (YME) and Poisson's Ratio (PR). In one example ofthe technique presented here, the YME and PR values are systematicallydetermined by the loading conditions of the bit in relation to the axisof material symmetry used to describe the rock formation.

In one specific implementation, the constitutive equations of linearelasticity are uniquely expressed through the application and use of MWDdata to (i) populate the variables of the constitutive equations oflinear elasticity and (ii) undertake an analysis of the constitutiveequations to obtain measurements of near-wellbore mechanical rockproperties of (a) Young's modulus of elasticity and (b) Poisson's ratio.Further, variations in the mechanical rock properties (e.g., YME and PR)are used to identify the nature and occurrence of mechanical boundariesor discontinuities in the subsurface such as fractures.

More specifically, a technique to determine near-wellbore mechanicalrock properties, YME and PR, from MWD data may involve processingmeasurements of the weight on bit (WOB), torque on bit (TOB), Annularfluid pressure (Ap), angular bit speed (RPM) and components of motiondescribing the acceleration of the bit, including axial, and the rotaryor tangential accelerations to (i) obtain sets of MWD data correspondingto known temporal and spatial positions along the borehole, (ii)calculate the forces acting on the rock formation in connection with thedrilling apparatus and drilling fluids, (iii) calculate thedisplacements of the bit as it is accommodated by the deformation of therock formation, (iv) inform the terms and loading conditions (variables)of a linear, elastic stress-strain relationship that describes theconstitutive behavior of the rock formation in relation to theorientation of the well and (v) using the constitutive linear elasticequations as determined through the application and use of the MWD datato calculate the aforementioned mechanical rock properties, (YME and PR)and (vi) analyzing the YME and PR with respect to the axis of materialsymmetry in relation to the orientation of the well to identify thenature and occurrence of mechanical boundaries and discontinuities suchas fractures and bedding planes among other things.

The present disclosure involves an innovative, new system, apparatus andmethod to specify, in general, the mechanical properties of a rockformation from an analysis of drilling vibrations generated by thecutting action of the bit and the deformation of the formation inresponse to the forces acting on the rock formation in connection withthe drill bit and drilling fluid system while conducting drillingoperations. Deformation may include elastic deformation, plasticdeformation, and failure of the rock, which may be consideredfracturing. Stated differently, aspects of the present disclosureinvolve obtaining information associated with the drilling of aborehole, while drilling, to identify mechanical rock properties of theformation being drilled. Such mechanical rock properties may be used, insome examples, to identify the presence of natural fractures or rockproperties more or less susceptible to stimulation techniques. Forexample, knowing mechanical rock properties along a borehole or thepresence of natural fractures along a borehole may be used to optimizehydraulic fracturing operations by focusing such fracturing on areaswhere it will be most effective, among other advantages. Mechanical rockproperties may include elastic coefficients (e.g., the cij's), strengthmeasurements such as initial yield strength, peak compressive strength,tensile strength YME, PR, shear modulus, bulk modulus, strain-hardeningexponents, Thompsen coefficients and other mechanical rock properties.

The Nature of Elastic Coefficients as they Pertain to Fractures

The mechanics of drilling a well provide a natural, in-situ, means tomeasure the deformation of a rock formation and gather data suitable fordetermining mechanical rock properties, because the penetration of thedrill bit is in and of itself accommodated by repeatedly fracturing therock formation by using the bit to generate forces on the rock formationthat are sufficient to overcome the failure strength of the rock,measurements of such in relation to the methods described here may beused in predictable ways to determine the presence of natural (in situ)fractures, fracture swarms (cluster of fractures), bedding planes, faultboundaries, and other information. In some instances, variations inmechanical rock properties are used to identify fractures, beddingplanes and the like.

Elastic coefficients that describe a relatively large deformation inresponse to the forces acting on a rock formation indicate the rockformation is weaker and less rigid. Therefore mapping the spatialvariations of the elastic coefficients provides information where thereare zones of weakness in the rock formation. If the nature andoccurrence of the zones of weakness in the rock formation as evidencedby changes in the elastic coefficients are localized in space orotherwise discrete relative to the surrounding elastic coefficients thatwould indicate the presence of a fracture or other mechanicaldiscontinuity. Systematic changes in the spatial distribution of theelastic coefficients as are derived by the method are used to identifymechanical discontinuities and geological boundaries of rock formationssuch as bedding planes or faults that act to separate or offset rockformation with different rock properties, where the differences in rockproperties are evidenced by the nature and distribution of the elasticcoefficients.

As will be understood from the present disclosure, mechanical strengthand deformation of the reservoir rock influences fracture creation,propagation and ability to maintain fracture permeability. FIG. 1 is asimplified diagram illustrating the difference between fractures inducedin a relatively brittle rock formation, and which may be includenaturally occurring fractures, versus fractures induced in a relativelyductile rock formation, which may include fewer or no natural fractures.As illustrated in FIG. 1A, a horizontal section 10 of a borehole hasbeen drilled through relatively brittle rock 12 and hydraulicallyfractured. In contrast, FIG. 1B illustrates a horizontal section 14 of aborehole drilled through relatively ductile rock 16 and hydraulicallyfractured. The fractures 18 created in the relatively brittle rock tendto penetrate deeper into the reservoir than the fracture 20 in ductilerock. Moreover, reservoir rock trending to the brittle end of the normalrange tends to have higher initial production rates and lower declinerates. The techniques described in this disclosure will provide newinformation for selecting hydrocarbon bearing zones by differentiatingbetween brittle rocks generally associated with larger fracture creationand better proppant support that is more permeable than ductile rockthat produces smaller, less productive fractures which are prone torapid compaction and closure and are less permeable. Similarly,techniques discussed herein may also identify areas where naturalfractures may exist provide similar advantages as brittle rock.Generally speaking, as will be understood from the disclosure, variousmechanical rock properties discussed herein will provide mechanismswhereby rock formations may be characterized, along the well bore, as tothe relative brittleness or ductileness, or the relative susceptibilityto stimulation techniques along the formation, which may include theidentification of existing fractures or at least rock propertiesindicative of existing fractures

Data Acquisition Techniques

FIG. 2 is a diagram of a bottom hole assembly portion 20 of a drillstring where the bottom hole assembly includes a drill bit 22, a mudmotor 24, a bit sub 26 including various measurement componentspositioned between the drill bit and the mud motor, and sections of pipe28 within a horizontal section 30 of a borehole, also referred to hereinas a well bore. The vibration data used in the described methodologiesmay be recorded as close to the source (drill bit) as practical to avoidattenuation through the bottom hole assembly. One possible location forrecording is directly behind the drill bit and ahead of the mud motorusing the bit sub, although multiple bit subs may be used along thedrill string for geophysical processing of the desired signal. Drillinga wellbore involves using a portion of the weight of the drill string,known as weight on bit, to push the drill bit into a formation 30. Therotating force on the drill bit, known as torque on bit, can come fromthe surface or from a mud motor close to the drill bit. When using a mudmotor, drilling mud is pumped down the drill string until it encountersthe power drive section of the mud motor where a portion of the mudpressure and flow is converted into a rotational force, which ismechanically coupled to the bit to thereby place rotational torque onthe bit 22 to turn the bit. The rotational force on the bit can also beaugmented by or come exclusively from mechanisms at the surface on thedrilling rig.

The objective of the drilling process is to break the rock down intofragments that are small enough that they can be lifted and evacuatedfrom the wellbore with drilling fluids in order to continue toaccommodate the forwards motion of the bit. It should be noted that theaction of the drill bit on a rock formation causes the fracturing of therock formation along the borehole to drill the hole, and in theformation immediately adjacent the borehole. Moreover, the drill mayencounter existing fractures 34 while drilling. Hydraulic fracturing, incontrast, is a process that occurs during the completion phase byinjecting fluid into the borehole, typically with perforation clusters22 in the casing, to initiate fractures 18/20 into the formationsurrounding the bore hole, as illustrated in FIG. 1.

In the illustrated diagram, the bit sub 26 is shown between the bit andthe mud motor. The bit sub is a cylindrical component that is operablycoupled between the mud motor 24 and the drill bit 22 in a way thatallows the mud motor to turn the bit. The bit sub provides housing,typically in a cylindrical shape, or mechanism to support variouspossible measurement components 36 including strain gauges, one or moreaccelerometers, pressure sensors, which may measure the pressure of themud flow, temperature sensors which may measure the circulatingtemperature of the mud or other temperatures and which may be used toprovide correction or offset of measurements or calculations that varywith temperature, gyroscopes which may be used to measure inclinationand/or directional changes of the bit and string, and/or othercomponents to measure or derive the information discussed herein.

In one example, as shown in FIGS. 2 and 2A, the strain gauges aremounted on the bit sub to determine torque on the bit and the weight onthe bit (the force turning the bit and the force pushing the bit intothe rock formation). Various possible ways of mounting the straingauges, or combinations of strain gauges, are possible. Additionally, asshown in FIG. 2A, which is a representative front view of the bit 22,accelerometers are placed to measure axial, rotary, and/or lateralacceleration of the bit. Note, the bit axis is in the center of thecircle, whereas axial acceleration may be measured somewhat offset fromthe axis depending on the placement of the accelerometer. Accelerationmeasurement may be accomplished by using one or more multi-axisaccelerometers. The bit sub, or other such component, may also include aprocessor and memory to store computer executable instructions toimplement various possible methodologies, and possibly preprocess data,as well as a power source which may be one or more batteries. Datastorage, such as the memory or other data storage, is also provided tostore the collected data. The measurement components, alone or invarious possible combinations, may be provided in other locations of thedrill string in the general proximity of the drill bit.

Geomechanics in Relation to the Cutting Action of the Bit

FIGS. 3A-3C are a sequence of diagrams illustrating a close up view of acutter 32 portion of a drill bit in a borehole, slipping, sticking on aportion of rock, and then slipping loose when the forces on the bit aresufficient to overcome the rock causing the rock to fracture and the bitto rotate—collectively referred to as stick slip behavior. The rockdeformation mode for a PDC bit is shearing as opposed to a roller conebit which is punching. Models that describe drilling behavior are in alarge part informed on the mechanics of drilling with a roller cone bitand while these models have been extended for the application and use ofPDC bits, they suffer uniquely from their inherent inability toreconcile the fundamentally different nature of rock deformation. Aswill be appreciated from this disclosure, the innovative, new techniquesdisclosed here seek to advance the application and use of PDC bits, aswell as other bits, to characterize mechanical rock properties and inparticular for the identification of the nature and occurrences offractures. The figures describe the depth of cut in relationship to thearea and displacement of the fractures created in response to the forcesacting on the bit. The cutting action of a particular type of bit butshould not be construed to limit the method in the use of other types ofdrill bits that generate acoustic emissions from rock failure inresponse to the forces acting on the geometry and configuration of thebit.

More specifically, as the bit turns, the interaction of the bit with therock formation at any instant in time, produces a complex distributionof forces acting on the formation in connection with the bit anddrilling fluid system (e.g., the mud motor) where the orientation andmagnitudes of the forces acting on the rock formation are related to theconfiguration and geometry of the cutters on the bit. Generallyspeaking, drilling is not a smooth and consistent process. Instead,depending many things including the axial force on the bit, rotationaltorque on the bit, rock properties, and presence or absence or existingfractures, the bit cuts, gouges, spins, snags, and otherwise drills theborehole in a very complicated and varying fashion. In some instances,the complex distribution of forces acting on the formation isinsufficient to initially overcome the strength of the rock formation inrelation to the cutting action of the bit and the bit will stop rotatingor stick.

As illustrated in FIGS. 3A and 3B, as the cutter begins to stick, thetorque applied to the bit increases from a relatively steady value. Asthe forces, such as the illustrated torque on bit, applied to the bitchange either through manual or automated interaction with the surfacedrilling apparatus or through the non-linear feedback of elastic energystored within the drilling string or some combination of both, a newweight on the bit (WOB) and torque are delivered to the bit. Theseforces on one or more particular cutters will continue to load the rockelastically until such point (i) the rock begins to deform plasticallyand the deformation is concentrated along fracture planes and (ii) whenthose forces provides a sufficient distribution of forces to overcomethe failure strength of the rock formation, the bit will turn and rock,often snapping loose, and drilling will continue. As shown in FIG. 3C,when the forces overcome the rock, the torque will dramatically drop tothe relatively steady value, until the bit sticks again. Such a stickslip action may occur at varying frequencies and displacements and makehappen one or more times per revolution of the bit per cutter on thebit, thereby resulting in many such cutting behaviors each revolution ofthe bit.

Regardless of whether and the extent of stick slip behavior isexperienced, deformation and failure of the rock cause the bit tovibrate. During rock deformation and in particular when the bitovercomes the rock strength at failure, stored elastic strain energy isreleased in the form of acoustic emissions. In some instances, the bitis fracturing rock and may intersect fractures and existing mechanicaldiscontinuities. In some instances, the bit may reactivate existingfractures, which may itself generate a distinct acoustical signal in theform of an induced bit vibration.

On the Processing of Drilling Vibrations

As introduced above, drill bits 22 typically include many cutters 32arranged with a geometry and configuration designed to generatesufficient forces to overcome the failure strength of the rock formation30 based on the nature of the rock formation expected to be encounteredwhen drilling a well. During a single rotation of the bit, at least one,but typically many of the cutters will overcome the failure strength ofthe rock formation and produce a plethora of acoustical emissionsrelated to the scraping, cutting, fracturing, and other interactionsbetween the bit and the rock formation. The tool may include variouspossible mechanisms, including a reed switch or gyroscopes, that measurerevolutions per minute and provide information of each rotation of thebit. There are as many as 30 cutter heads, so each rotation may causehundreds of acoustic pulses.

Because of the stochastic nature of acoustic emissions or in relation tothe nearly simultaneous initiation and propagation of multiple fracturesat the cutting face, the implementation of the method discussed hereinmay use statistical methods and signal analysis tools. In one possiblemethodology, the RMS measurement technique determines the energy of thesignal despite the shape of its waveform. This is important because themany simultaneous events will create complex waveforms with constructiveand destructive interferences.

Given the stochastic nature of the acoustic emissions generated by thecutting action of the bit, it is expected that the more times the bitturns per unit time, the higher the rate of acoustic emissions. RMSlevels obtained for a time window that underwent two revolutions of thebit would be expected to have higher RMS levels than those obtainedduring one revolution of the bit in the same time window, all otherthings being equal.

Measurements while drilling show that the bit speed can vary wildly anderratically during drilling operations. In some instances the bit cancompletely stick and then slip again as more force is gradually applied.If the stick-slip behavior of the drill bit is not accounted for in thegeophysical signal processing, then the variations in the fracturemeasurements may be confused by with variations in the bit speed and notvariations in the fracturing behavior of the rock. When the time windowused to measure the RMS level of the signals that have been extractedfrom the drilling vibrations is normalized with respect to the bitspeed, where the bit speed is recording using a gyro to sample thechanges in position of the bit with respect to time or a magnet which isused to inform the position of the bit with respect to time, thisnormalized measurement is understood to provide a level of theacoustical emission activity generated by the fracturing of a rockformation in relation to the cutting action of the bit. The time windowwhere data is gathered may be tied directly to bit rotation by having atime window set based on counts of the bit revolution. In otherinstances, the time window may be set, and the energy (from vibrations)may be normalized to account for some set turns of the bit, such as oneturn of the bit.

The implementation of the technique as described uses signal processingtechniques, such as Fourier transforms, bandpass filtering or otherfiltering, or combinations thereof, to calculate the motion of the bitand the forces on the bit from the amplitudes and frequencies of theacoustical signals recorded by the MWD apparatus (e.g. bit sub 22) thatare generated in response to the cutting action of the bit (e.g., thedrilling vibrations propagate up the drill string as acoustic wavessometimes referred to as collar waves or tool mode, where they arerecorded as acoustical signals by the MWD apparatus). Forces on the bitmay also be measured using strain gauges, in one possibleimplementation. The motion of the bit and the forces on the bit are usedto populate a stress/strain relationship that allows the computation ofmechanical rock properties. Mechanical rock properties may be analyzedrelative to a baseline (such as an average over some wellbore distance)to identify locations where the mechanical properties of a rockformation change as the bit encounters a mechanical discontinuity orother geological discontinuity all other things being equal. In someinstances, rock properties may be used to identify such locationsthrough computations based on assumptions of the rock formation, andcomparisons thereof, or otherwise.

Referring to FIG. 4, to account for the effects of the drillingefficiencies and the possibility of stick-slip behavior while conductingdrilling operations, in one specific implementation, the method may usemeasurements of the drilling efficiencies, such as revolutions perminute (RPM) to normalize the geophysical signal processing of thedrilling vibrations in order to compare the results of the signalprocessing along the length of the borehole in accordance with themethods provided. It is understood through the normalization that thevariations in the signal levels, such as the RMS levels, are nowcorrected in account of the changes in drilling efficiencies along thetrajectory of the borehole.

As such, the RMS levels, obtained as shown above, for example, arerelated to changes in the mechanical rock properties while the drillintersects areas of differing properties. Stated differently, it may behelpful to compensate or normalize for changes in the rotational speedof the bit (RPM) by using a time window commensurate with the rotationof the bit. Such normalization may also be useful to correct thegeophysical signal processing in accordance with drilling operationswhere the drill string is rotated from surface in conjunction with themud motor turning the bit, as opposed to situations where the mud motoris operating but the string is sliding not being rotated from thesurface.

In a further elaboration of the method, the signal processing techniquessystematically relate measurements of the forces acting on a rockformation in connection with the drill bit and drilling fluid system(stress) to the variations in the fracturing of a rock formation inresponse to the cutting action of the bit (strain) to obtain innovative,new stress-strain relationships where the application and use of thestress-strain relationships allow for the derivation of elasticcoefficients for the stress-strain relationships. Relative variations ineither one or a combination of the elastic coefficients may be used toidentify the nature and occurrence of fractures, fracture swarms andother mechanical discontinuities and geological boundaries such asbedding planes and/or faults that offset or otherwise separate rockformations with different mechanical rock properties.

Accounting for the drilling efficiencies is also a consideration in theimplementation of the approach, because the wear on the drill bit as therock formation is drilled will change the configuration and geometry ofthe cutters on the drill bit. The mechanical wear of the drill bit willaffect the distribution of the forces acting on the formation inconnection with the drill bit and as the well is progressed, the manualor automated application of forces on the drilling apparatus change toaccount for the wear and tear of the bit.

The application and use of the stress-strain technique according themethod employed herein is understood to normalize the effects of reduceddrilling efficiencies caused by bit wear on the derivation of themechanical rock properties because the forces used in the stress-strainrelationship are obtained from the forces acting on the bit, where theforces needed to overcome the strength of the rock are increased inrelation to the penetration or depth of cut of the worn bit tooth intothe formation.

The acoustical emissions associated with the deformation and failure ofthe rock formation while drilling are generally too minute and/or tooattenuated by the intervening rock to be detectable at the surface(which may be hundreds or thousands of feet above the borehole). Becauseof the amount of energy released is generally expected to be slight andof relatively high frequency, the radiated waves are best viewed whentransmitted from the cutting face through the bit and bottom holeassembly where they propagate along the drill string throughacoustically conductive steel as a direct tool arrival and contribute tothe vibration of the drill string. The drilling vibrations can berecorded on instrumentation that is sensitive to their nature andpresence. Stated differently, one aspect of the present disclosureinvolves a drilling tool assembly including sensors and processingelectronics (e.g., the accelerometers and/or strain gauges in the bitsub 26 proximate the bit 22) that are positioned to detect and recordthe radiated waves from the drilling induced fracturing, which mayfurther involve identification and/or characterization of existingmechanical discontinuities, such as fractures or geological boundaries,such as faults or bedding planes.

A Specific Data Logging Technique

In one specific implementation, a form of measurement while drilling(MWD) system or tool is employed. The MWD system uses sensors designedto measures vibration. The MWD system may also measure forces on thebit, and other parameters such as bit speed, which may be expressed asrevolutions per minute, the fluid pressures, and temperature of thedrilling mud or environment proximate the bit sub. The system may alsoinclude gyroscopes to obtain the orientation of the cutting face of thedrill bit, in some implementations. In one specific embodiment, the MWDtool includes at least one receiver, accelerometers which may includestrain gauges mounted on or proximate the bottom hole assembly to recordthe drilling vibrations and associated acoustic emissions. In someimplementations, the MWD may further include electrical, mechanical,and/or other filtering mechanisms to processes the data to removeunwanted noise or to record the data without unwanted noise. In certaininstances, stages of filtering may be applied both prior to recording,and after recording but prior to processing, to remove unwanted data, oras much as necessary or possible. In an alternative enablement, thesignals may be transmitted to the surface for storage and processing. Insome applications it may be desirable to process the acoustical signals,such as through the processor, on board the logging tool fortransmission of the significantly data-reduced processed signal tosurface in real time.

Once the drilling dynamics data is collected and processed, the resultsare correlated back to the measured depth of the well using precisemeasurements of the length of drill string components as they arelowered into the well. Gamma ray LWD and casing collar measurements canfurther be used to correlate the absolute location of data processedfrom the BHA collection point or points to determine a more reliablelocation of the bit in relation to the subsurface.

Noise Attenuation Techniques

Because of the amount of energy released is generally expected to beslight and of relatively high frequency, the radiated waves are bestviewed when transmitted from the cutting face (with cutters 32) to thebit and bottom hole assembly, where they may further propagate and areknown as the direct tool arrival or collar wave and contribute to thevibration of the drill string. The acoustic emissions may be measured byaccelerometers, transducers, or other devices sensitive to particlemotion.

Drilling induced vibrations that are generated by the interaction of thebit with the rock formation will have harmonic frequencies that arerelated to the rotational speed of the bit. Most of the harmonicvibrations are expected to be low frequency. The amplitudes of theacoustical emissions in the frequency ranges of the harmonic frequenciesare usually much less than the amplitude of the harmonic drillingvibrations. In one implementation, the harmonic drilling vibrations areremoved by a filter, such as a high pass filter or bandpass filter,which may be implemented in the bit sub processor, or may be applied tothe stored data for later processing after download of the data from thebit sub memory, that passes signal frequencies that are higher thanfrequencies related to the harmonic drilling vibrations, and which mayalso eliminate frequencies above those possibly related to fracturecharacteristics. Other filter types and frequency characteristics willbe possible depending on various factors including, but not limited to,the rotational speed of the bit, the type of bit, the rockcharacteristics, the positioning of sensors, mud motor characteristics,and other attributes.

Another consideration with respect to the variations in the amplitudeand frequency of the acoustic emissions is the interference of thedirect tool arrival by the generation and transmission of other wavemodes that are also excited by the drilling operations including thewave modes excited by the release of energy from the fracturing of therock formation.

In addition to the acoustical emissions created by the fracturing of arock formation in response to the cutting action of the bit, thedrilling vibrations that are being recorded will also generate wavemodes that propagate though the formation surrounding the wellbore andthe fluids within the wellbore that can interfere with the acousticalemissions that are related to the fracturing of a rock formation at thecutting face and bias the measurements of the mechanical rockproperties. For some frequencies, the other wave modes will have higheramplitudes than the amplitudes of the acoustical emissions at thatparticular frequency. These other wave modes will result from thepropagation of various guided waves in the drilling fluid between thebottom hole assembly and the wellbore such as Stonely waves, tube wavesand direct fluid waves such as the fluid compressional waves. Other wavemodes that can interfere with the direct tool arrival are surface wavesthat propagate and refract energy along the interface between the wellbore and the fluid such as compressional head waves, surfacecompressional waves and shear body waves. These waves all have thepotential to interfere with the propagation of energy from the directtool arrival and if their presence is included in the signal processingcould bias the calculations related to the amplitudes and frequenciesused to describe the nature and occurrence of the fracturing.

To decrease the possibility of interference with the other wave modes,in one embodiment the sensor is mounted internally using in a plug whichwill effectively isolate the sensor from the wave modes propagatingthrough the formation and through the fluids. For example, in the caseof accelerometers, the accelerometers are mounted within the bit sub (orother component). External waves that are carried by the formation andfluid in the annulus 36 will therefore be mechanically isolated by theinternal position of the sensor relative to the other waves. Aninternally mounted sensor will be respond mainly to the vibrationsrelated to direct tool arrival (the vibrations caused by the interactionof the bit with the formation).

Because the steel used in the construction of a bottom assembly has asignificantly higher quality factor, Q of 10,000, that rock formationsand fluids where Q ranges are typically from 1 to 100, the waves thatpropagate along the collar known as the collar wave or tool arrival willexperience much less attenuation than signals recorded by the sensorthat have traveled through the formation or the fluid media. Because ofthe low attenuation of the waves propagating along the steel drillcollar relative to the waves propagating through the formations anddrilling fluids, it could also be possible to naturally attenuate thevarious unwanted modes of propagation by placing the receiver at adistance that is far enough away from the bit to attenuate the otherunwanted formation and fluid wave modes that will interfere with thedirect tool arrival, but not so far as to lose the valuable highfrequency information carried by the collar wave or tool wave that isneeded to be recorded to calculate the size and displacement of thefracturing. The distances needed to attenuate the unwanted modes can bedetermined by expressions that relate the energy loss per cycle duringtransmission for a given quality factor. In this embodiment the locationof the bottom hole assembly in relation to the location of the bit isplaced at a distance behind the bit to achieve this attenuation.Alternatively or additionally, to avoid the interference of fluid andformation arrivals with the collar arrival the receiver may be coupledto the drill string at the surface of the well where the drill stringhas yet to enter the subsurface and borehole that contains the drillingfluids.

In another embodiment, a plurality of receivers are arranged along thestring behind the drill bit to record the acoustical signals generatedby the release of elastic energy at the cutting face. In one example,the receivers are spaced within centimeters or millimeters and may beplaced in array mounted on a portion of the bit sub. The spacing of thereceivers may form an array, with the spacing determined by thefrequency range of the acoustical signals and the velocity ofpropagation in the steel or other material. Because the velocity ofpropagation in the steel is typically much faster than most formationand fluid velocities which control the nature of propagation of theinterfering modes and is known with a high degree of certainty, spatialfilters such as FK filters that pass signals that propagate atvelocities that are consistent with wave transmission through steel andattenuate events with slower velocities. These filters can be used toseparate the direct tool arrival waves from the other interferingwaveforms. When using an array of receivers the signal-to-noise ratiocan be further increased by using geophysical signal processingtechniques to filter the data by stacking the signals over the array.The nature of the stacking depends on the configuration of the array ofreceivers and whether the receivers are deployed in a linear, bipolar orradial array.

In some instances the stacking can be used to isolate various modes thatare propagated by the tool arrival, such as the compressional wave,transverse wave or quadrupole wave. These other tool modes can also beprocessed using geophysical signal processing techniques to determinethe fracturing of a rock formation in relation to the cutting action ofthe bit.

The quadrupole is a direct tool mode that does not propagate direct toolarrivals above a cutoff frequency, where the cutoff frequency is relatedto the diameter and thickness of the steel. The amplitudes andfrequencies of these other modes provides useful though otherwise bandlimited information that may be used in relation to the geophysicalsignal processing techniques in order to specify how the size anddisplacement of the fractures would be responsible for generating theseother wave modes.

The analysis of the signals extracted from the drilling vibrationsshould not be limited to the case of the amplitudes and frequencies ofthe direct tool arrival. In another embodiment, the receiver array canbe used to reject the direct tool arrival or collar wave and pass otherarrivals related to other modes of transmission, where the modes oftransmission may be through the rock formation or drilling fluid systembased on their velocity of propagation and frequency content through themedia. These other modes of propagation may be used in preference to thedirect tool arrival when the other modes of wave propagation containsignals related to the fracturing of the formation in relation to thecutting action of the bit that are of interest to the variations of theRMS levels of the signals as described by the method.

The Application and Use of Microseismic Signal Processing Techniques inRelation to the Method

In a further elaboration of the method, drilling vibrations generated bythe cutting action of the bit may be processed using geophysical signalprocessing techniques that are conventionally recognized as appropriatefor the analysis of microearthquake source mechanisms. In one example,the depth of cut or penetration per revolution of the bit is obtained byusing signal processing techniques to measure the sizes anddisplacements of fractures that result from the deformation and failureof the rock formation in relation to the cutting action of the bit, toestimate the zero-frequency level (ZFL) of the displacement spectra. TheZFL of the displacement is the static offset level here understood torepresent the penetration of the bit. Under this consideration and inrelation to the technique it provides high resolution motion of the bitthat is taken to be the depth of cut or penetration of the bit for eachrevolution of the bit.

FIG. 5 illustrates a displacement spectra for one revolution of a bit.The graph of displacement spectra has a y-axis of rotary displacementamplitude at a range of frequencies (x-axis) over which amplitudemeasurements are taken (based on the sampling frequency.) Thedisplacement spectra is obtained by integrating the Fourier transform ofthe time domain measurement of the acceleration data (bit vibrationdata) twice in the frequency domain, or the angular velocity time seriesonce where it is understood that the accelerations may be axial,lateral, rotary or a combination of those channels. Rotary displacementmay be in the form of radians. The ZFL (zero frequency level) determinedby the method is where the displacement spectra theoretically intersectsthe zero-frequency axis. The ZFL is directly proportional to the averagedisplacements of the fractures initiated by the bit, and to thedisplacement of the bit per revolution.

Generally speaking, because high resolution displacement data isachievable, the system can detect relative changes of displacement perrevolution of the bit or displacement per time or rate of penetration(ROP) and thereby determine when a fracture is encountered as thedisplacement will be greater relative to areas where fractures are notencountered. With respect to the method, the increase in displacementwould indicate a change in the hardness of the formation, where hardnessincreases with displacement all other things being equal.

Observations of strong ground motion generated by earthquakes suggestthat the time series recordings of the P- and S-wave signals can bereasonably and effectively treated as band limited white noise where theamplitudes and frequencies of the signals are controlled by theinteraction of many smaller faults and fracture patches rupturingsimultaneously and the band limitations in the absence of attenuationare related to the displacements and rupture dimensions of earthquakesource. Therefore, observations involving the simultaneous occurrence ofmultiple acoustic emissions generated by fracturing at the face of thebit and then transmitted through steel where the signals are expected toundergo little attenuation indicates that the application and use ofmodels that are generally used to describe the source mechanisms of anearthquake can be used to describe the aggregate sizes and displacementsof many fractures being generated simultaneously from the repeatedturning of the many cutters on the drill bit when overcoming the rockstrength to accommodate the motion of the bit.

The estimation of the size and displacement of the fracturing generatedby the cutting action or motion of the bit follows directly from thedisplay of the data that is present in FIG. 5. Here the model forrepresenting the microearthquake source mechanism that estimate the sizeand displacement of the fracturing typically involves the applicationand use of a two parameter spectral model where here the two parametersused to describe the model are the zero-frequency level of thedisplacement spectra and the corner frequency. It should be appreciatedthat other source parameter models such as the RMS stress drop that alsouse the amplitude and frequencies of the signals to estimate the sizeand displacement of fracture and can also be considered and the use of atwo parameter spectral model should not limit the scope of this method.

In the two parameter model of the microearthquake source mechanism, thedisplacement of the bit as determined by the displacements on thefractures is related to the zero frequency level of the displacementspectra. The zero frequency level of the displacement spectra is thesame as the static offset. The low-frequency content may be modified bythe receivers and electronics used to record the signals on the MWDassembly and the possible use of band pass filters in relation to thesignal processing to eliminate the low frequency drilling harmonics. Thetechnique has advantages because it (i) provides an estimate of the ZFLusing band-limited data that may not always be reliable in the lower endof the amplitude spectra, (ii) provides a reliable technique toobjectively select the ZFL without manual or visual biases, (iii) can beautomated in a computer implemented fashion to handle the large volumesof data typically collected by an MWD apparatus as used to collect datain relation to the method.

Geophysical signal processing techniques that use relationships betweenthe power spectral density of the displacement and velocity spectrum areused to calculate this value (ZFL) based on the functional mathematicalrepresentation of the earthquake source spectra as described by the twoparameter spectral model of the earthquake source provide an objectivetechnique to overcome the expected poor signal to noise ratios of thelow frequency acoustical information.

Thus, ZFL is understood to represent the displacement or penetration ofthe bit. In one specific example, the ZFL is a measurement of thedisplacement (e.g., in millimeters or inches or angular displacementssuch as a radians) of the bit per turn of the bit. If the displacementis the axial displacement per revolution of the bit, then thisdisplacement can be used to inform a depth of cut in terms ofdisplacement per revolution. If time taken to make the one turn of thebit is used to describe the axial displacement or penetration of thebit, then it is taken that this may be used to determine rate ofpenetration. Typical depths of cut as estimated by the method range from0.01 inches per revolution to 0.1 inches per revolution

The size or the radius of the fractures can also be determined by thefrequency content of the acoustical signal. Signals with higherfrequency content generally correspond to smaller fracture areas. Thischaracteristic of the frequency spectra that is used to determine thesize of the event is typically referred to as the corner frequency (FIG.5). There is a linear, relationship between the corner frequency of thedisplacement spectra and the size of the event. Because of attenuationof the signal during the transmission, estimates of the corner frequencymay be compromised if the sensor is placed too far from the bit. Thus,having the sensors as close to the bit as possible, or at least not sofar that attenuation is significant, may be a consideration for someimplementations discussed herein. Limitations in the sensor and therecording electronics and the filters employed to extract the signalsmay also limit the useable bandwidth.

Geophysical signal processing techniques that use relationships betweenthe power spectral density of the displacement and power spectraldensity of the velocity based on the functional mathematicalrepresentation of the earthquake source spectra as is described by thetwo parameter model of the earthquake source that can be used tocalculate the corner frequency. A relatively high corner frequency mayrepresent unfractured rock whereas relatively lower corner frequency mayindicate the presence of a fracture.

When the bandwidth is limited, the minimum fracture size detected willbe set to a threshold based on a cutoff frequency. Any fracturing of arock formation below this threshold will not contribute to thedetermination of the fracturing of the rock formation and thedeformation of the rock formation. Thus, in the application of themethod, some rock formations may undergo fracturing in response to thecutting action of the bit where the fracturing is not detected by themethod employed here, either because the frequencies of which tofracture energy occur are too high or the signal to noise ratio is toolow. The occurrence of these scenarios would suggest that the bit is noteffectively penetrating the formation and that the rock propertiesderived in this instance would represent the limiting rock propertiesand limit the specification of the deformation of the rock in responseto forces generated by the emplacement of hydraulic fractures where anysuch deformation in relation to the cutting action of the bit would betaken as insufficient to do so.

In order to make meaningful comparisons of the fracture sizes anddisplacements along the well bore, the time window that is used toprocess the signals extracted from the drilling vibrations is based onthe bit speed, in one specific implementation. One way to normalize thetime window relative to the bit speed is to specify the time windowaccording to the time needed to make one revolution of the bit. If thebit speed were 120 RPM then the time window would be 500 ms, while ifthe bit speed were 60 RPM then the time window would need to be 1000 msto obtain an equivalent measurement of the fracturing generated inresponse to the cutting action of the bit. Another way to normalize thetime window to account for variations in the bit speed along thewellbore would be to normalize the temporal frequency of the spectraldensity by converting from cycles per second to cycles per revolution.At a bit speed of 120 RPM, the bit would make two revolutions in asecond and therefore at cycle per second would be normalized to twocycles per revolution, while a bit speed of 60 RPM would make onerevolution in a second therefore one cycle per second would benormalized to one cycle per revolution. In one embodiment, the BHA isinstrumented to measure the bit speed at sufficient resolution tospecify either a time window equivalent to one rotation of the bit ornormalize the spectral density by converting the temporal frequency tocycles per revolution.

As such, the spatial variations in the measurements as obtained througha combination of one or more of the measurements such as the RMSacceleration or the sizes and displacements of the fractures areunderstood to correspond to the nature and occurrence of deformation andfailure in relation to the cutting action of the bit and as such aretaken to represent the spatial variations in mechanical rock properties.So, an increasing value of ZFL, relative to a baseline, represents theintersection of the bit with zone of mechanically weaker rock that maybe determined to be a fracture, swarm of fractures (e.g., fracture 34)in accordance with for example a stress-strain relationship. Therefore,the geophysical signal processing techniques employed by the method mayinvolve statistical descriptions such as measuring the RMS level of theacoustical emissions or the application and use of geophysical signalprocessing techniques that are generally recognized as appropriate forthe analysis of microearthquake source mechanisms to describe thedeformation and failure of a rock formation in relation to the cuttingaction of the bit, where the spatial variations in the measurements(e.g., changes in ZFL or corner frequencies) relative to some average orbaseline level are used to identify mechanical discontinuities orgeological formations as they are encountered or crossed by the bit.

In another embodiment, referring now to FIG. 6, the geophysical signalprocessing methods may obtain measurements related to the instantaneouschange in the inclination of the bit relative to the average directionof the bit to describe a mechanical discontinuity or geologicalboundary. Instantaneous change in inclination of the drill bit relativeto a long-term average inclination can be obtained using a sensor or anarray of sensors configured to record and extract acoustical signals inrelation to the independent spatial axes of the drilling vibrations. Themagnitude of the deflection of the inclination of the drill bit relativeto a long-term trend in the direction of the drill bit depends on theorientation of the mechanical discontinuity or geological boundary withrespect to the cutting face of the drill bit and therefore thedeflection is understood to indicate a change in the mechanical rockproperties. So, for example, with a multi-axis accelerometer measuringaxial acceleration and lateral or rotary acceleration of the bit, theratio of the axial and lateral or rotary displacements may be treated asan inclination, as illustrated in the respective inclination logs 60(prior to the fracture, while the bit 22 intersects the existingfracture 34). The lateral or rotary acceleration will increaserelatively when the bit is deflected from axial movement, such as whenthe bit encounters an angled discontinuity transverse the borehole.

The Concept of Specific Energy in Relation to the Method

In addition to acoustical information that informs the displacement ofthe bit, aspects of the present disclosure may further involve forceinformation. While conducting drilling operations the energy defined asthe energy needed to remove a volume of rock is useful to describe theefficiency of the drilling operation. The specific energy is a term thatdescribes the minimum amount of work needed to remove a certain volumeof rock. Descriptions of the specific energy are useful to understandthe variations in rate of penetration or the depth of cut in relation tothe forces acting on the bit. Unlike conventional methods, the specificenergy here may be calculated from the aforementioned acousticalprocessing techniques in and of themselves or in conjunction withmeasurements of torque on bit and/or force on bit.

The size and displacement of the fractures that form in response to thecutting action of the bit controls depth of cut into a rock formationand subsequently the rate of penetration of the drill bit through a rockformation. In a method described here, the work done per the volume ofrock removed is determined by the displacement of the fractures asmultiplied by the area of the bit. The work is computed from the forcesacting on the bit multiplied by the displacement of the bit. Asdiscussed above, the displacements of the bit are obtained through theanalysis of the drilling vibration using geophysical signal processingtechniques that are appropriate for the analysis of microearthquakesource mechanisms as is provided by the above discussed method.

There are two components of the specific energy: one that is normal tothe bit and another that is tangential to the bit or rotary energy.Because the rotary specific energy is proportionally related to thetorque per unit of displacement, it provides a measure of the rockstrength or the minimum energy needed to drill and the application anduse of the rotary specific energy in this regard takes the form of astress-strain relationship (FIG. 8 and others).

In the method provided here, the displacement of the bit as it relatesto the fracturing of the formation is evidenced through the RMS level ofthe measurements or the displacement of the bit is evidenced by thedisplacement on the fractures as provided through the microearthquakesource parameter measurements and the volume of rock removed isproportional to the fracture areas and the fracture displacement areaveraged over all of the fractures provides in the period of timeprocessed for the time period that is analyzed for example in a singleturn of the bit. In one embodiment of the method, the volume of rockexcavated is specified by the product of the aggregate area of thefractures and the average displacement of the fractures removed by oneturn of the bit.

For a bit that is turning at a rate of 120 RPM this would involve usinga time window of 500 ms to the average area and average the displacementfor one revolution of the drill bit. It should be appreciated that ininstances when the rock properties are varying slowly or the MWDmeasurements are updated at rates less than the time period of one bitrevolution the method is not limited to periods that are specified bythe turning rate of the bit.

The rotational specific energy is the torque over the average fracturedisplacement per revolution as obtained by the analysis of the vibrationdata disclosed by this technique, provides a novel, innovativestress-strain relationship (FIG. 8 and others). For a given rock type,this is expected to be a linear relationship where the slope of the lineis related to an elastic coefficient describing the strength of the rock(e.g., specified rock strength 1 (70), specified rock strength 2 (72),and specified rock strength 3 (74)). Because the measurements areobtained while drilling, the strength of the rock actually determined byand is intrinsically related to the fracturing in response to thecutting action of the bit. When using a polycrystalline diamond compact(PDC) bit, for example, the strength of the rock determined from thisstress strain relationship would be directly related to the shearstrength of the rock. Stress-strain measurements obtained using themethod disclosed can be used to characterize the elastic coefficients ofthe rock formation.

Innovative Stress Strain Relationships as are Provided by the Method

The stress strain relationships employed by the method are populatedfrom measurements taken while drilling. In one instance, the strain isunderstood to be related to the depth of cut or the penetration perrevolution of the bit which is determined by differencing the spatiallocation at two instances in time versus the number of revolutions takenfor the bit to travel that distance. In accordance with the methods setout here in, where (i) the drilling vibrations are understood torepresent the deformation and failure of a rock formation in response tocutting action of the bit in order to accommodate the forward motion ofthe bit through a rock formation, and (ii) the drilling vibrations asprocessed through the signal processing techniques to evidence themotion of the bit per turn of the bit are understood to represent strainand (iii) the RMS acceleration as obtained through the geophysicalsignal processing techniques to evidence the forces acting on the bitper turn of the bit in are used to populate the variable in relation toa stress-strain constitutive equation. In a further elaboration, thesestrain measurements can be related to the forces such as the weight onbit and torque on bit acting on the formation in connection with the bitand drilling fluid system to provide a diagram of a generalstress-strain relationship. By relating the orientation and magnitude ofthe stress with respect to the orientation and magnitudes of the strain,where the orientations and magnitudes of the stress and strain arerelated to the geographical coordinates of the well, multiplestress-strain relationships can be established to determine the elasticcoefficients of a rock formation. Where the well is drill perpendicularto the maximum horizontal compressive stress, it is understood thatthese stress-strain relationships are expressed in the principle axes.

In general, the deformation of a homogeneous isotropic rock formationcan be specified by two elastic coefficients. As the complexity of therock formation increases through the presence of mechanicaldiscontinuities and geological boundaries, the number of elasticcoefficients needed to fully describe the deformation of a rockformation in response to the forces acting on the formation in generalincreases.

The simplest elastic coefficient would be to relate the WOB to thestrain generated by the cutting action of the bit where the strain isthe displacement in relation to a length made by one turn of the bitwhere the time windows used for the geophysical signal processingtechniques are related to the bit speed. In one preferred embodiment ofthe method, the WOB would be obtained from the RMS acceleration, wherethe component of acceleration is oriented parallel to the borehole andas is illustrated.

For a transverse isotropic (TI) media, the stress strain relationshipconstitutive equation is illustrated in FIG. 8A (using MWD data) withattendant PR intercept and YME slope information illustrated in thecurves of FIG. 8B.

Where:

E is Young's Modulus of Elasticity (YME),

ν is Poisson's ratio (PR)

σ1=TOB

σ3=WOB

ε3=Axial displacement spectra ZFL

This stress-strain relationship would in general be proportional to aYoung's modulus of elasticity where YME is determined parallel to thedirection of drilling. The method allows for the determination ofelastic coefficients for transverse isotropic elastic media, where theassumption of transverse isotropic elasticity is understood to bereasonable approximation to describe the rock deformation by obtainingthe stress-strain relationship to the orientation geological boundarieswith respect to the inclination of the bit of the well being drilled.This could be accomplished using FIG. 8 or FIG. 10C where the elasticcoefficients as described are proportional to Young's Modulus and thePoisson's ratio of a rock formation.

In another implementation more particularly shown in FIGS. 9A and 9B,the rock strength is specified by the stress-strain relationships basedon the orientation of the well in relation to the bedding planes of thehydrocarbon bearing formation and the orientation of the well withrespect to the principle axes of tectonic stress or the state-of-stressacting on the rock formation. This method allows for the determinationof elastic coefficients for a transverse isotropic (TI) elastic media,where the assumption of transverse elasticity is taken as a reasonableapproximation to describe the rock deformation by obtaining thestress-strain relationship to the orientation geological boundaries withrespect to the inclination of the bit of the well being drilled. Thiscould be accomplished using the above description where the elasticcoefficients as described are proportional to Young's Modulus and thePoisson's ratio of a rock formation.

The loading conditions on a rock formation are given by the forcesacting on the rock formation in connection with the drilling apparatus(e.g., weigh on bit and/or torque on bit) and drilling fluid system(e.g., annular pressure) and the deformation of the rock formation aredescribed by the displacements of the bit (e.g., axial and lateral orrotary displacements as measured by accelerometers in the bit sub). Theconstitutive equations are described with respect to transverseisotropic media. As shown in FIG. 9A-9B, transverse isotropic mediainvolves a layering of media (sometimes referred to as “layercake”).Transverse isotropic media involves a layering of media that is normalto a plane of isotropy—meaning the media is relatively uniform aroundthe axis of symmetry. FIG. 9A illustrates a case where the axis 90 ofmaterial symmetry is parallel to the borehole 94 (and parallel to thebit axis 96 drilling the borehole). FIG. 9B illustrates a case where theaxis of material symmetry 98 is perpendicular to the borehole. In onepossible implementation, it is assumed that the media is eithervertically transverse isotropic (VTI) or it is horizontally transverseisotropic (HTI). VTI is a case where the axis of symmetry is verticallyoriented (layers are horizontal with respect to the free surface). HTIis a case where the axis of symmetry is horizontally oriented (where theanisotropy is understood to involve a layering of the formation that isvertical with respect to the free surface and further where it isunderstood that fractures represent a case of vertical layering withrespect to the free surface). Thus, in the case of a vertical well, FIG.9A illustrates vertical transverse isotropy (the vertical borehole isparallel to a vertical axis of isotropic layer symmetry) and alsoillustrates, in the case of a horizontal well, horizontal transverseisotropy (the horizontal borehole is parallel to a horizontal axis ofisotropic layer symmetry). In contrast, in the case of a horizontalwell, FIG. 9B illustrates vertical transverse isotropy (the horizontalborehole is perpendicular a vertical axis of isotropic layer symmetry)and also illustrates, in the case of a vertical well, horizontaltransverse isotropy (the vertical borehole is parallel a horizontal axisof isotropic layer symmetry).

FIGS. 9A and 9B also illustrate the variables for the constitutivestress-strain equation (FIG. 8 and FIG. 10C) of a transverse isotropicmedia. The stress strain variables are populated based on either (i)force measurements (e.g., from strain gauges) and/or (ii) theacceleration measurements (e.g., from accelerometers) or populated onlyform acceleration data. More specifically, in the first case, thestress-strain variables are populated with data related to WOB, TOB oraxial or lateral or rotary displacements. In the second case, the stressstrain variables the forces are populated with axial and lateral orrotary acceleration data, and the strain from the axial or lateral orrotary displacements (which may be available by integrating the axial orlateral or rotary acceleration spectra twice in the frequency domain).Generally speaking, Poisson's ratio (and/or Young's modulus) is computedfrom stress-strain constitutive equations populated from measurementstaken while drilling along a borehole under the assumption that thetransverse axis of material symmetry is parallel to the borehole (FIG.9A) and under the assumption that the transverse axis of materialsymmetry is perpendicular to the borehole (FIG. 9B).

When the rock formation (media) is isotropic, the two equations willgenerate values of PR or YME that generally track each other, meaningthat under either assumptive case, the drill bit will react similarly asit drills through relatively uniform rock and therefore the twocalculations of PR and YME, while different, will nonetheless track eachother. If, however, the borehole intersects discontinuities and or morethe media is anisotropic, the computations of PR and/or YME will nolonger track each other. The stress-strain relationships may be recastinto other equivalent forms, and the particular arrangement shown inFIGS. 8, 9, and 10 are taken for the sake of conveniences and should notbe considered limiting. In a particularly useful manner as shown in FIG.11, the constitutive equations could be re-arranged so that the Young'smodulus term is determined using the slope of a linear relationship ifthe equations were cast in terms of the ratio of the forces actingparallel to the axis of symmetry to the forces acting perpendicular tothe axis of material symmetry.

In certain instances, such as drilling under high confining annularpressure, the confining pressure may be more accurately described usingthe annular pressure instead of WOB. In such a case, AP would be used inplace of WOB for the cases illustrated in FIGS. 9A and 9B, and possiblyothers.

Some of the stress strain relationships are set out in terms of bi-axialloading accounting for weight on bit and torque on bit. However, itshould be understood that an implementation accounting for tri-axialloading may nonetheless use and account for WOB and TOB or the RMSacceleration.

Thus, in the application of the stress-strain relationships for alayered media, where the bedding planes are horizontal a vertical welland a horizontal well are drilled through the same rock formation where:

-   -   1. Separate stress-strain relationships that describe the        elastic coefficients when the bit is cutting perpendicular to        the geological boundaries such as the bedding planes and when        the bit is cutting parallel to the geological boundaries would        enable at least four elastic coefficients to be determined which        can be used to describe in general, stress-strain relationships        of transverse isotropic rock formations.    -   2. Separate stress-strain relationships that describe the        elastic coefficients when the bit is cutting parallel to the        direction of maximum horizontal compressive stress and parallel        to the maximum vertical compressive stress would enable at least        four elastic coefficients to be determined.

Referring to FIG. 10C, under the two assumptions (TI axis parallel toborehole and TI axis perpendicular to borehole (FIGS. 9A, 10A and 9B,10B)), there are two values for PR and two values for YME, with PR andYME being elastic coefficients.

In practical application, the rock formation may not be actuallyhorizontal or vertical, but may be tilted. When drilling through titledmedia, particularly media with small deviated angles of less than 30degrees, given the expression of the trigonometric variables in relationto a rotation of the principle axis, the equations still produce usefulresults for PR and YME and may be used to inform the variation in themechanical rock properties and in particular inform the location offractures where the variation of the mechanical rock properties ispredicted to do so as is described below.

On the Calculation of the Elastic Coefficients YME and PR Through aMechanical Rock Property Analysis (MRPA) of the Method

FIG. 12 is a diagram illustrating linear stress strain relationshipswith curves fit to data pairs corresponding to different locations alonga bore hole. The slopes of the fit lines in these examples relate to YMEin different locations along a bore hole. To obtain data for populatingthe constitutive equation (or equations), various geophysical dataprocessing techniques are involved, where:

-   -   1. Sampling the MWD measurements at a sufficiently high        frequency to resolve a small degree of mechanical variability        (which may correspond to the nature and occurrence of a discrete        fracture a couple of mm wide), the measurements of the forces        acting on a rock formation in connection with a drilling bit,        (TOB and WOB) and fluid system pressure or annular pressure        (Ap), the angular speed of the bit expressed in revolutions per        unit of time (RPM) and the 3-components of motion that represent        the acceleration of the bit and where each of the measurements        taken in time corresponds to a discrete position of the bit        along the length wellbore (the MWD data)    -   2. Processing accelerations may be processed using geophysical        signal processing techniques to obtain (i) the average lateral        or rotary and vertical displacement of the bit that correspond        to a single revolution or turn of the bit and (ii) Root Mean        Squared (RMS) amplitude of the acceleration    -   3. Calculating the RMS averages of the TOB and WOB over time        windows that correspond to a single bit turn. Typical        penetration rates are usually 0.02 in/rev, while drilling at 240        rpm, would result in a single turn of the bit every 250 ms which        if sampled at 1 kHz would provide sufficient data to be able to        identify when the bit encounters a single-discrete fracture    -   4. Obtaining data pairs, which collectively define the linear        stress strain relationship, from MWD data using relationships        between the rms acceleration and displacement of the bit that        are appropriate for the loading conditions and motion of the bit        in relation to the axis of symmetry for the constitutive        equations used to describe the rock formation where it is        understood that the loading conditions are determined with        respect to the orientation of the drilling well.    -   5. Using curve fitting techniques to estimate the two parameters        needed to describe a line, the Slope and Intercept and        statistical descriptions of the variations of the two elastic        parameters YME and PR with respect to each of the linear        clusters as were identified with respect to the band-limited MWD        data that was used to generate the data pairs    -   6. Identifying where the distributions of the MWD data pairs        form spatially or temporally consistent clusters or otherwise a        locus of adjacent points that (i) can be described through the        application and use of curve fitting techniques in terms of        relationships that are linear and (ii) such that each of the        linear relationships can be used to determine the parameters of        line such as the slope and intercept in relation to the        mechanical rock properties YME and PR.

In one possible example, a set of data pairs are generated for theequation of FIG. 9A (10A) and/or the FIG. 9B (10B). The data pairs aregenerated along the length of a well bore. In one example, a data paircomprises (y, x) and the set of data pairs may be used to generate thelinear stress strain relationships illustrated in graphical form in FIG.12 for each of the cases shown in FIGS. 9A and 9B.

In one embodiment, the variables of the equations are populated using(i) the RMS acceleration data, which is used to describe the forcesacting on the formation in connection with the bit, and (ii) the ZFL ofthe displacement spectrum is used to describe the motion on the bitwhere the motion understood to be the strain experienced by the rockformation and where the orientations of strain are described by the bitdisplacements according to the cutting direction of the bit and theorientation of the borehole in relation to the orientation of the axisof material symmetry as is shown in Figure. Thus, the acousticalacceleration measurements may use to specify the forces acting on theformation. The approach essentially conforms with Newton's second lawand balance of forces.

Special Cases to Consider

As shown, the MWD parameters may be expressed as a function of thefrequency content. In particular, where the frequency content is limitedthrough the application and use of a band-pass filter to generateband-limited MWD data pairs to populate the terms and conditions of theconstitutive equations of linear elasticity, using band-limited MWD datato form frequency-dependent, data pairs corresponding to data thatgenerally describes the stresses acting on the material and thedeformation of the material to populate the terms and conditions of theconstitutive equations of linear elasticity. Using geophysical signalprocessing techniques to obtain zero-frequency levels (ZFL) of thedisplacement spectra where the ZFL corresponds of depth of cut perrevolution of the bit or the depth of cut per unit of time or the rateof penetration (ROP) in relation to the width of the bandpass filterused to window the MWD data (the band-limited MWD data). That is the ZFLis determined from a specified range of frequencies or is otherwisecalculated from bandlimited data.

Using the two parameters YME and PR and the statistical descriptions ofthe variations of the two parameters as can be obtained through thecurve fitting technique for each liner cluster to diagnose the drillingconditions for each of the depths as a function of the frequency used toform the data pairs.

Fracture Identification from the Elastic Coefficients

It is usually not known a priori what the appropriate angularrelationships between the axis of symmetry of the constitutive elasticequations used to describe the rock formation and the axis of symmetryof the wellbore are. In practice, most horizontal wells are drilledparallel to bedding and most vertical wells are drilled perpendicular tobedding. Further, in basins, most natural fractures are vertical, andthus most horizontal wells are drilled perpendicular to fractures andmost vertical wells drill parallel to fractures.

Referring again to FIGS. 9A and 9B, the MRPA technique is used topopulate the terms and conditions of the two assumptive cases where theaxis of symmetry of the constitutive media used to describe the rockformation are examined for the cases when (i) the axis of materialsymmetry is perpendicular to the axis of drilling and (FIG. 9A) (ii) theaxis of material symmetry is parallel to the axis of drilling (FIG. 9B).In an isotropic media, the determination of YME and PR from the MRPAanalysis for the two constitutive stress strain relationships willresult in equally or closely spaced values of YME and PR that tend totrack each other in space and time. In anisotropic media, the twocomputations of YME and PR as provided by the MRPA will deviate inpredictable ways that can be used to identify the nature and occurrencefractures in relation to (i) the differences in the elastic coefficientsas specified by the type of anisotropy, either HTI or TVI, that isencountered relative to the orientation of the drilling well and (ii)the reduction in strength of the rock as is provided by variations inHTI YME and the TVI YME.

In the case of a horizontal well when the constitutive equationsdescribe a variation in the end members situations (i) the rock may beunderstood to be fractured when PR TVI is lower than PR HTI and themagnitude of the fracturing is related to the decrease in thecalculation of YME. Typically, in practice, fractured zones can bediscerned in horizontal wells when the media is TVI PR is lower than theHTI PR. The difference in the values of the elastic coefficients YME andPR between the HTI and VTI represent two cases of a cross-over curve oran anisotropic cross-over curve.

In the case of a vertical well, the rock is understood to be fracturedwhen HTI PR is less than TVI PR (e.g., FIG. 13, discussed in more detailbelow). An objective way to determine these cross-over relationships (PRor YME for the two assumptive cases) is by calculating a series in timeor a series in depth (the logs) of the YME or the PR for both the TVIand HTI solutions. Time or depth may be correlated to length along thewell bore from which the measurements were made.

Mechanical rock property logs (the “Logs”) as calculated using theequations set out by the method can be smoothed by averaging the PR andYME values by (i) using the statistics in relation to the goodness offit to the curve where one such statistic is known as the R statistic asprovided by standard least-squares linear curve fitters such as LINESTin Excel, to filter out data with poor statistical evidence for a linearrelationship between the data pairs or (ii) to weight the values of thecurve at a particular location. Using a curve smoothing technique thatwould average the data over a time window where the length of the timewindow corresponded to the variation of the data and then resampling thetime window in either time or depth according to its position in thesubsurface. Processing logs using smoothing techniques can improve theability to identify the relative variations in the elastic coefficients.

Further processing the logs by subtracting the mean value from the HTIand TVI YME Logs where the mean value is a running average of the dataalong the Log where the length of the running average is related to:

-   -   (1) the measure of the smallest length of mechanical anisotropy        variation of interest which in terms of the practice and        application of the method may involve spatial distances as small        as 1 inch for the sample rate and frequency content that is        afforded by the application of use of state-of-the-art MWD in        relation to the method        -   AND    -   (2) of sufficient resolution to document the nature and        occurrence of changes in rock properties needed to identify        fractures at the resolution need for the commercial exploitation        of commercial hydrocarbons from unconventional reservoirs.

The subtraction of the mean value of from the HTI and TVI PR Logsprovides a baseline from which to compare the variations between thecurves in ways that can be used to identify the locations of fractures.In practice the mean values of the Logs can be calculated as the averageof the data values in the logs over a certain time or distance specifiedby the spatial position in the subsurface along the length of thewellbore from which the measurements were made. When this mean value issubtracted from the Logs it provides the mean-subtracted Logs from whichto make it convenient to obtain relative comparisons (e.g., PR HTI to PRVTI and/or YME VTI to YME HTI).

Taking differences of the mean-subtracted YME HTI Log and themean-subtracted YME TVI Log and taking the differences of themean-subtracted PR HTI log and the mean-subtracted PR TVI log providesan identification of the type of rock anisotropy based on theorientation of the well in relation to the axis of material symmetry.The differences in these Logs as evidenced by the behavior of theelastic coefficients in relation to the orientation of media symmetrywith respect to the orientation of the wellbore can be can be understoodin predictable ways to describe the location of a zone of weakness inrelation to the method understood to be a fracture. For the casespresented here, these relationships provide a predictable way toidentify fractured rock formations, among other advantages

Specific Case 1: Vertical Well, Horizontal TI Media

In typical TVI media, the vertical PR (FIG. 9A—TI axis parallel toborehole) typically has lower values than horizontal PR (FIG. 9B TI axisperpendicular to borehole). That is, the material is more compliant to aload that is applied perpendicular to the axis of material symmetry thanto a load applied parallel to the axis of material symmetry. Loading therock formation in the same direction as the axis of material symmetrywill result in less horizontal deformation, decreased horizontalcompliance and/or higher ratios of horizontal to vertical stiffness.Conversely, loading the rock formation perpendicular to the axis ofmaterial symmetry, when the material symmetry is governed by fractures,will have higher compliances, higher PR and lower YME.

Stated differently, in a vertical well when the media is layercake (theaxis of media symmetry is parallel the borehole), the weight on bit andaxial displacements are typically parallel to the axis of materialsymmetry. In this case the VTI PR is typically less than HTI PR.Therefore, detection of zones where PR VTI is greater than PR HTIimplies that the material behavior under the loading conditions of thebit is stiffer or less compliant in the horizontal direction as opposedto the vertical direction. Referring to FIG. 13, when a vertical wellencounters HTI media (in a formation expected to be VTI), themean-subtracted PR HTI log becomes less than the mean-subtracted PR TVIlog, and a Fracture ID flag may be generated. This flag means the ratioof the displacement parallel to the axis of material symmetry increasesrelative to the displacement perpendicular to the axis of materialsymmetry. This is evidenced through the application and use of MWD datato describe the constitutive behavior of a rock formation anddemonstrate an increase in PR TVI relative to PR HTI. This increase inPR evidences the presence of vertical fractures or a verticallyfractured rock formation when drilling a vertical well. This logic isgenerally true is most circumstances, because most vertical wells aredrilled perpendicular to the bedding planes of the rock formation wherethe well bore axis is parallel to the axis of material symmetry and sothe presence of high VTI PR values is probably not related to verticalbedding planes. This behavior of a vertically drilling well encounteringa set of vertical fractures can be further corroborated by a similarexamination of the differences between the VTI YME and the HTI YME.Because the torque on bit is acting as a body force parallel to the axisof material symmetry as would be expected in the case of a verticallydrilling well encountering a set of vertical fractures where thefractures control the axis of material symmetry, the VTI YME decreasesand the HTI YME increases.

When the YME TVI log crosses or decreases relative the YME/HTI log for ahorizontal well then it is likely a zone of weakness that is morecompliant in the direction of loading that is parallel to the WOB orperpendicular to the axis of material symmetry has been detected whichwould again be consistent with a zone of vertical fractures. So, in someinstances, PR crossover would generate a flag, YME crossover wouldgenerate a flag, and in some instances the presence of both flagsindicate a fracture. Moreover, in practice, a threshold may be appliedthat would need to be met before generating a flag. In one example, forPR data, a distribution curve may be generated for all positivecrossovers, and only crossovers exceeding 68th or 90th or 95thpercentile may be flagged. Other thresholds or data technique may alsobe used to eliminate data points that may be attributable to noise.

When the relationship between the HTI and TVI elastic constants returnsto a pre-crossover relationship for a vertical well in an HTVI media,the crossover Fracture ID flag is set back to zero. The flag may remainset, however, for as long as the log indicates. So, as shown in theexample of FIG. 13, there are six sections of the 100 foot illustratedborehole where fractures are identified over several feet for eachsection.

Specific Case 2: Horizontal Well, Horizontal TI Media

FIG. 14A illustrates the two YME computations (FIG. [ ]A and FIG. [ ]B)over about 100 feet of horizontal well. FIG. 14B illustrates PR ratiocomputations (also FIG. [ ]A and FIG. [ ]B) over the same 100 fee ofhorizontal well. The YME and PR computations are based on data obtainedwhile drilling. In this case, only the geophysical processing of theacoustical data as obtained from the accelerometers are used to populatethe equations, so not direct measurements of WOB or TOB are provide inthis example, but they could be included in another application and useof the equations as provided by the method. In the example illustratedin FIGS. 14A and 14B, a fracture ID may be generated where shown. Inthis case, effectively the opposite behavior than was described for avertical well drilling parallel to the axis of symmetry or HTVI orlayercake, is expected because now, in the case of a horizontal well inTI media, the axis of drilling is perpendicular to the axis of mediasymmetry. In this case, the loading conditions (torque on bit) areparallel to the axis of material symmetry conditions and rotationaldisplacements (revolutions of the bit) are also parallel to the axis ofmaterial symmetry and HTI calculation will result in a lower HTI PR.

In the case of a horizontal well encountering a vertical fracture, therelationship is expected to be similar to a vertical well drilling in aHTVI media—the PR HTI will decrease relative to the mean-subtracted PRVTI. More specifically, in the event with the mean-subtracted VTI PR fora horizontal well drilling in a layercake media is found to be less thanthe mean-subtracted HTI PR, then it is likely that the axis of materialsymmetry relative to the orientation of the drilling well and loadingconditions of the bit has been rotated by 90 degrees. This can occurwhen the axis material symmetry is defined by a set of verticalfractures being intersected by a horizontal well. Thus, as shown, forexample in FIGS. 14A and 14B, a fracture flag may be identified in theidentified areas, as well as possibly other areas.

Likewise, the mean subtracted TVI YME will increase relative to themean-subtracted HTI YME when the material symmetry is as defined by aset of vertical fractures because torque on bit will be loadingperpendicular to the axis of material symmetry. In this example thecross-overs are not always synonymous as can be expected for real rockwhere a continuum of mechanical rock properties will occur based on thenatural heterogeneity of a complex, natural system where it isunderstood that the detection of fractures from among various therelationships between these cross-overs is just one implementation amongothers.

Among the advantages of the method is to use the values of thedifferences in the elastic coefficients between the various types ofcross-over than can be expected from the method where in simple casesfracture flags identified by the simultaneous cross of both YME and PRcurves as is afforded by the method, to other cases of mechanical rockheterogeneity that is caused by the occurrence of only one curvecrossing over the other or vice versa. Here this may lead to additionalfracture classification schemes that would involve the cross-over of oneset of coefficients relative to the other.

Elastic coefficients and the variation in the elastic coefficients wherethe variation of the elastic coefficients is determined in oneparticular application though the differences as obtained by asubtraction and of the elastic coefficients for the HTI and VTIinstances as is specified by the orientation of the well in relation tothe axis of material symmetry. When the variations determined from thestress-strain relationships based on the geographical orientation of thewell relative to the bedding planes provide an indication of fracturesin accordance with the manner described here would provide usefulinformation for the design the emplacement of hydraulic fracturestreatments and the selection of hydraulic fracture initiation points.

Other Improvements as are Envisioned by the Method

In one embodiment, the wellbore is drilled laterally through anunconventional shale reservoir. The natural variations in the strengthof an unconventional shale reservoir could be viewed by plotting aplethora of stress-strain relationships that could be derived inassociation with every single turn of the bit (FIG. 8). This wouldcreate a scatter plot that can be analyzed by using statistical methodsto find significant relationships in the data that are used to classifythe nature of the rock deformation based on the groupings of themechanical rock property data on the stress-strain diagram.

These classified rock strength measurements may be indexed according totheir spatial location along the well bore trajectory. Classification ofthe type of rock deformation such as strong or weak, brittle or ductilebased on the mechanical rock properties and in particular the elasticcoefficients in the stress-strain diagrams when logged using the MWDsystem could be used to identify and select zones along the wellboreselection of hydraulic fracture initiation points for the emplacement ofhydraulic fractures.

Other stress-strain relationships can be developed in the mannerdescribed here where the forces acting the formation in connection withthe bit are the effective stress obtained by differencing the force andthe fluid pressures in the drilling system or the Torque acting on thebit. In another embodiment the orientation and geometry of the cuttersin relation to the WOB and Torque can be used to describe tractions thatare normal and tangential to the cutting face and be used to specifyadditional coefficients of elasticity as provided by the method. Thenormal traction can be modified by the drilling fluid pressures tocalculate effective normal stress acting on the cutting face of the rockformation. When the effective normal stress and shear stress can beprojected onto a fault place where the fault plane undergoesreactivation as evidenced by the methods here, when used in conjunctionwith a failure criterion, can provide critical information on thestate-of-stress in the reservoir.

Inclination Measurements as Provided by the ZFL Measurements

Referring again to FIG. 6, it is understood that changes in theinclination of the bit, detectable with MWD data in combinations of thevarious forms discussed herein, may also identify discontinuities alonga bore hole. More specifically, as illustrated, if the drill bitencounters a mechanical discontinuity or geological boundary, thecutting face of the drill bit may change its orientation is response tothe orientation and stresses acting on the heterogeneity. Instantaneouschanges in inclination of the drill bit relative to a long-term averageinclination can be obtained using a sensor or an array of sensors (e.g.axial and lateral or rotary accelerometers) configured to record andextract signals in relation to the three, independent spatial axes ofthe drilling vibrations. The magnitude of the deflection of theinclination of the drill bit relative to a long-term trend in thedirection of the drill bit depends on the orientation of the mechanicaldiscontinuity or geological boundary with respect to the cutting face ofthe drill bit and therefore the deflection is understood to indicate achange in the mechanical rock properties. If there is an indication of afracture based on the RMS levels of the other measurements, but nocorresponding deflection in the bit, then it is understood that theorientation of the mechanical discontinuity is perpendicular to theorientation of the well bore trajectory. The magnitude of the deflectionof the drill bit can be determined through a principle componentanalysis of the signals extracted from the drilling vibrations where thetime window used to obtain principle components of drilling motion ofthe signals may be normalized by the bit speed and where the principlecomponents can be expressed as changes in the rate of penetration (ROP)or the acceleration of the drill bit.

Discrete Microearthquake Detection Method to Identify a Fault

Referring now to FIG. 15 if the forces acting on the formation inconnection with the drill bit and drilling fluid system when conductingdrilling operations are sufficient to overcome the failure criteria of apre-existing fault, then the fault will slip or fail. Reactivation of afault or pre-existing fracture can be evidenced by extracting a signalfrom the drilling vibrations that is related to a microseismic eventwith attendant primary, compressional (P) and secondary, or shear (S)arrivals. In the case where the fault is perpendicular to the trajectoryof the wellbore the P-wave arrival is related the particle motionparallel to the axis of the drill string and the S- or transverse waveis the particle motion parallel to the lateral and torsion motion of thedrill string. Deviations of the particle motion of the P- and S-wavescan be used to determine the orientation of the fault relative to thetrajectory of the wellbore.

Reactivation of a fault is expected to create much larger signals aretypically expected from the acoustic emissions generated by thefracturing of a rock formation in relation to the cutting action of thebit. By looking at the instantaneous amplitude levels relative to along-term trend, where the temporal windows used to select theinstantaneous amplitudes are related to the bit speed and the long-termwindow is related to the spatial distribution of the faults in the rockformation, it is possible to identify the location where the bitencountered and crossed a fault.

In the special case of a fault reactivation while conducting drillingoperations, the sensors deployed on the bottomhole assembly act like anearthquake seismometer where the geophysical signal processingtechniques identify the discrete arrivals of P-waves and S-waves withorthogonal particle motions to detect the presence and reactivation of apre-existing fault. If the orientation of the fault with respect to theorientation and magnitude of the forces acting on the formation inconnection with the bit and drilling fluid system can be determined thenthis would enable a method to specify in 3-dimensions a failurecriterion of the fault.

Geosteering or Real-Time Applications of the Method

Stick-slip drilling behavior causes the bit speed, typically expressedin revolutions, per minute to increase or decrease according to thedistribution of forces acting on the formation in connection with thebit. The variations of the bit speed with respect to the forces used tofracture a rock formation to achieve optimum rates of penetration aretypically used to describe the efficiency of the drilling operation,where there is an optimum efficiency that maximizes the rate ofpenetration with respect to the forces acting on the bit

Techniques that can determine the deformation of a rock formation bydescribing formation fracturing while conducting drilling provide thatwhen these techniques are enabled in real-time implementations using MWDsystems and apparatus, they also can be used to “geosteer” thehorizontal well at the bit by maintaining the trajectory of the wellborein the hydrocarbon bearing zone that experiences fracturing generated bythe cutting action of the bit in relation to the forces acting on theformation in connection with the bit and drilling system that hasbearing on the mechanical rock properties that will enhance theeffectiveness of hydraulic fracture emplacements.

Example embodiments described herein regarding the various controlmethods may be implemented at least in part in electronic circuitry; incomputer hardware executing firmware and/or software instructions;and/or in combinations thereof. Example embodiments also may beimplemented using a computer program product (e.g., a computer programtangibly or non-transitorily embodied in a machine-readable medium andincluding instructions for execution by, or to control the operation of,a data processing apparatus, such as, for example, one or moreprogrammable processors or computers). A computer program may be writtenin any form of programming language, including compiled or interpretedlanguages, and may be deployed in any form, including as a stand-aloneprogram or as a subroutine or other unit suitable for use in a computingenvironment.

FIG. 16 is a flowchart illustrating one method conforming with aspectsof the present disclosure. It should be recognized that the elaboratedetail and various alternatives and embodiments set out herein mayconstitute other methods, alone or in combination with that set forth inFIG. 16. Moreover, various steps of the method of FIG. 16, as well asother methods, may be performed within a computer system such as set outin FIG. 17 or may be performed, in whole or in part, in a bottom holeassembly associated with or proximate a bit, such as shown in FIG. 2,may form or be used in steering and may therefore be deployed in thegeosteering system illustrated in FIG. 2 or may be deployed in variousmechanisms associated with completions. Referring to FIG. 16, the methodinvolves receiving acoustical signals obtained from one or more sensorspositioned on a component of a bottom hole assembly (operation 1610).The sensors (e.g., accelerometers) are in operable communication with atleast one data memory to store the acoustical signals (e.g., vibrationdata) where the acoustical signals are generated from a drill bitinteracting with a rock formation while drilling a wellbore. The methodfurther involves processing the acoustical signals to obtain at leastone set of data values representative of a mechanical rock property ofthe rock formation along the wellbore created by the drill bitinteracting with the rock formation for a period of time (operation1620). After which, the method may involve identifying a change in theat least one set of data values, where the change is representative ofthe drill bit crossing a mechanical rock property discontinuity whiledrilling the wellbore (operation 1630). In some instances, the methodmay further involve using the data to complete the well (operation1640).

FIG. 17 is a block diagram of a machine in the example form of acomputer system 1700 within which instructions 1706 for causing themachine to perform any one or more of the methodologies discussed hereinmay be executed by one or more hardware processors 1702. In variousembodiments, the machine operates as a standalone device or may beconnected (e.g., networked) to other machines. In a networkeddeployment, the machine may operate in the capacity of a server or aclient machine in server-client network environment, or as a peermachine in a peer-to-peer (or distributed) network environment. Further,while only a single machine is illustrated, the term “machine” shallalso be taken to include any collection of machines or controllers thatindividually or jointly execute a set (or multiple sets) of instructions706 to perform any one or more of the methodologies discussed herein,including that set out in FIG. 16 as well as the various methodologiesdiscussed herein to obtain and/or compute ZFL, axial displacement,rotary displacement, axial and rotary accelerations, bit displacement,RMS values of various measurements, Poisson's ratio, Young's modulus ofelasticity, and others.

As depicted in FIG. 17, the example computing system 1700 may includeone or more hardware processors 1702, one or more data storage devices1704, one or more memory devices 1708, and/or one or more input/outputdevices 1710. Each of these components may include one or moreintegrated circuits (ICs) (including, but not limited to,field-programmable gate arrays (FPGAs), application-specific ICs(ASICs), and so on), as well as more discrete components, such astransistors, resistors, capacitors, inductors, transformers, and thelike. Various ones of these components may communicate with one anotherby way of one or more communication buses, point-to-point communicationpaths, or other communication means not explicitly depicted in FIG. 17.Additionally, other devices or components, such as, for example, variousperipheral controllers (e.g., an input/output controller, a memorycontroller, a data storage device controller, a graphics processing unit(GPU), and so on), a power supply, one or more ventilation fans, and anenclosure for encompassing the various components, may be included inthe example computing system 1700, but are not explicitly depicted inFIG. 17 or discussed further herein.

The at least one hardware processor 1702 may include, for example, acentral processing unit (CPU), a microprocessor, a microcontroller,and/or a digital signal processor (DSP). Further, one or more hardwareprocessors 1702 may include one or more execution cores capable ofexecuting instructions and performing operations in parallel with eachother. In some instances, the hardware processor is within the bit sub,and others it is part of another separate processing system.

The one or more data storage devices 1704 may include any non-volatiledata storage device capable of storing the executable instructions 706and/or other data generated or employed within the example computingsystem 1700. In some examples, the one or more data storage devices 1704may also include an operating system (OS) that manages the variouscomponents of the example computing system 1700 and through whichapplication programs or other software may be executed. Thus, in someembodiments, the executable instructions 1706 may include instructionsof both application programs and the operating system. Examples of thedata storage devices 1704 may include, but are not limited to, magneticdisk drives, optical disk drives, solid state drives (SSDs), flashdrives, and so on, and may include either or both removable data storagemedia (e.g., Compact Disc Read-Only Memory (CD-ROM), Digital VersatileDisc Read-Only Memory (DVD-ROM), magneto-optical disks, flash drives,and so on) and non-removable data storage media (e.g., internal magnetichard disks, SSDs, and so on).

The one or more memory devices 1708 may include, in some examples, bothvolatile memory (such as, for example, dynamic random access memory(DRAM), static random access memory (SRAM), and so on), and non-volatilememory (e.g., read-only memory (ROM), flash memory, and the like). Inone embodiment, a ROM may be utilized to store a basic input/outputsystem (BIOS) to facilitate communication between an operating systemand the various components of the example computing system 1700. In someexamples, DRAM and/or other rewritable memory devices may be employed tostore portions of the executable instructions 1706, as well as dataaccessed via the executable instructions 1706, at least on a temporarybasis. In some examples, one or more of the memory devices 1708 may belocated within the same integrated circuits as the one or more hardwareprocessors 1702 to facilitate more rapid access to the executableinstructions 1706 and/or data stored therein.

The one or more data storage devices 1704 and/or the one or more memorydevices 1708 may be referred to as one or more machine-readable media,which may include a single medium or multiple media that store the oneor more executable instructions 1706 or data structures. The term“machine-readable medium” shall also be taken to include any tangiblemedium that is capable of storing, encoding, or carrying instructions1706 for execution by the machine and that cause the machine to performany one or more of the methodologies of the present invention, or thatis capable of storing, encoding, or carrying data structures utilized byor associated with such instructions 1706.

The input/output devices 1710 may include one or more communicationinterface devices 1712, human input devices 1714, human output devices1716, and environment transducer devices 1718. The one or morecommunication interface devices 1712 may be configured to transmitand/or receive information between the example computing system 1700 andother machines or devices by way of one or more wired or wirelesscommunication networks or connections. The information may include datathat is provided as input to, or generated as output from, the examplecomputing device 1700, and/or may include at least a portion of theexecutable instructions 1706. Examples of such networks or connectionsmay include, but are not limited to, Universal Serial Bus (USB),Ethernet, Wi-Fi®, Bluetooth®, Near Field Communication (NFC), and so on.One or more such communication interface devices 1710 may be utilized tocommunicate one or more other machines, either directly over apoint-to-point communication path or over another communication means.Further, one or more wireless communication interface devices 1712, aswell as one or more environment transducer devices 1718 described below,may employ an antenna for electromagnetic signal transmission and/orreception. In some examples, an antenna may be employed to receiveGlobal Positioning System (GPS) data to facilitate determination of alocation of the machine or another device.

In some embodiments, the one or more human input devices 1714 mayconvert a human-generated signal, such as, for example, human voice,physical movement, physical touch or pressure, and the like, intoelectrical signals as input data for the example computing system 1700.The human input devices 1714 may include, for example, a keyboard, amouse, a joystick, a camera, a microphone, a touch-sensitive displayscreen (“touchscreen”), a positional sensor, an orientation sensor, agravitational sensor, an inertial sensor, an accelerometer, and/or thelike.

The human output devices 716 may convert electrical signals into signalsthat may be sensed as output by a human, such as sound, light, and/ortouch. The human output devices 1716 may include, for example, a displaymonitor or touchscreen, a speaker, a tactile and/or haptic outputdevice, and/or so on.

The one or more environment transducer devices 1718 may include a devicethat converts one form of energy or signal into another, such as from anelectrical signal generated within the example computing system 1700 toanother type of signal, and/or vice-versa. Further, the transducers 1718may be incorporated within the computing system 700, as illustrated inFIG. 17, or may be coupled thereto in a wired or wireless manner. Insome embodiments, one or more environment transducer devices 1718 maysense characteristics or aspects of an environment local to or remotefrom the example computing device 1700, such as, for example, light,sound, temperature, pressure, magnetic field, electric field, chemicalproperties, physical movement, orientation, acceleration, gravity, andso on. Further, in some embodiments, one or more environment transducerdevices 1718 may generate signals to impose some effect on theenvironment either local to or remote from the example computing device1700, such as, for example, physical movement of some object (e.g., amechanical actuator), receiving or processing accelerometer data, straingauge data, and the like.

SUMMARY

As such, under the aforementioned considerations the spatial variationsin the MWD data in particular the MWD vibrations as obtained through acombination of one or more of the measurements are used to describevariations in mechanical rock properties where the variations andoccurrences of the can be described as fractures based on the methodsused here. Here calculations made using signal processing techniques areused to populate innovative new stress-strain relationships.

The method discloses how the spatial variations in one or more or acombination of the mechanical rock properties as can be obtained fromthe stress-strain relationships used to identify the nature andoccurrence of fractures, fracture swarms and other mechanicaldiscontinuities (boundaries) such as bedding planes and/or faults thatoffset or otherwise separate rock formations with different mechanicalrock properties.

The present disclosure uses an innovative, new methodologies todetermine the deformation of a rock formation by systematically relatingforces acting on a rock formation in connection with the drill bit anddrilling fluid system to the geophysical signal processing of drillingvibrations generated by the fracturing of the rock in response to thecutting action of the bit to obtain a strain measurement. This approachallows elastic coefficients to be derived that can be used, in general,to describe the general deformation of a rock formation in response tothe forces acting on a rock formation.

The elastic coefficients can be used to determine the deformation of ahydrocarbon bearing formation in response to the forces acting on theformation during the emplacement of hydraulic fractures in connectionwith hydraulic fracture stimulation treatments and in particular basedon the spatial variations of the elastic coefficients select hydraulicfracture initiation points for the purpose of enhancing theeffectiveness of the hydraulic fracture emplacements in low permeabilityhydrocarbon bearing rock formations (FIG. 9).

Methods that can in general understand and predict the nature andoccurrence of fracturing along a wellbore are important considerationsfor the specification and design of hydraulic fracture stimulationtechniques because decisions to either eliminate zones that do notexperience brittle deformation or select zones that exhibit more brittledeformation relative to other zones can be used to improve the economicsof the production. Further where the rock deformation is accommodated byfailure of pre-existing fractures, these pre-existing fractures shouldbe avoided when setting packers during the pumping operations or theycan be targeted for hydraulic fracture stimulation depending on thedesired approach to be used when completing the well.

The following is a list, albeit not exhaustive or limited to only thelist, of innovations.

A method of processing drilling vibration information to obtain one ormore measurements such as the RMS acceleration or the sizes anddisplacements of the fractures where the measurements are understood tocorrespond to the motion of the bit and in particular where the motionof the bit is expressed in the ZFL of the displacement spectra to informthe depth of cut as a displacement per revolution or displacement pertime to make a revolution. Therefore, spatial variation in the of themotion of the bit in relation to the forces acting on the bit aresystematically investigated using stress-strain constitutive equationswhere the variables are populated using geophysical signal processing ofthe MWD data to obtain the forces acting on the bit and the motion ofthe bit in relation to the forces in order to solve for the elasticcoefficients where the elastic coefficients are the YME and PR and wherethe elastic coefficients are determined using stress-strain constitutiverelationships that represent the case of where the drilling isperpendicular to an axis of material symmetry and parallel to an axis ofmaterial symmetry when the elastic coefficients are taken to representspatial variations in mechanical rock properties where the spatialvariations are used in predictable ways such are used to identifyfractures, fracture swarms and other mechanical discontinuities(boundaries) such as faults and bedding planes that offset or otherwiseact to separate rock formations with different rock properties.

A further method of processing drilling vibrations in relation to theforces acting on a rock formation in connection with a drill bit anddrilling fluid system to specify stress-strain relationships to deriveelastic coefficients that in general predict the deformation of a rockformation and in particular, in one form are used to predict thedeformation of a hydrocarbon bearing formation in response to the forcesacting on the hydrocarbon bearing formation where the forces aregenerated by the emplacement of hydraulic fractures along a horizontalwell to enhance the effectiveness of hydraulic stimulation treatments ina hydrocarbon bearing rock formations generally involves the following:

-   -   (1) Deploying sensors or an array of sensors that are sensitive        to the amplitudes and frequencies of the drilling vibrations        generated in response to the fracturing in relation to the        cutting action of the bit using an instrumented sonde attached        to a bottomhole assembly to record one or more axis of the        drilling vibrations and where the sonde may employ sensors to        record the drilling efficiencies such as the bit speed and the        forces acting on the formation in connection with the drill bit        and fluid pressure changes created by the circulation of the        drilling fluids while conducting drilling operations.    -   (2) Extracting signals from the drilling vibrations that are        related to the elastic energy released by deformation and        failure of the rock formation in response to the cutting action        of the bit that are transmitted from the rock formation in        connection with the bit to the receivers through the drilling        collar to the instrumented sonde in the bottomhole assembly by        filtering the unwanted noise and other interfering modes of wave        propagation not related to the tool arrival, generally involves        using at least one or a combination of filters through the        application and use of (i) mechanically isolated sensors from        energy transmitted through the rock formation and drilling fluid        system (ii) bandpass or FK spatial filters, (iii) multiple        receivers to stack the signals and attenuate the random noise        or (iv) placing the sonde in a position in the drill string that        is sufficiently far enough away from the bit to attenuate the        higher frequencies of the unwanted wave arrivals.    -   (3) Using geophysical signal processing techniques to measure        the temporal and spatial variations in the amplitude and        frequency of the signals as can be extracted or otherwise        derived from the drilling vibrations to determine the nature and        occurrence of fracturing, fracture swarms and other mechanical        discontinuities (boundaries) such as faults and bedding planes        that offset or otherwise act to separate rock formations with        different rock properties using one or a combination of:        -   a. RMS measurements of the signals extracted from the            drilling vibrations where the signals may be expressed in            terms of displacement, vibration or acceleration, and where            the time windows used for the RMS calculation may be            normalized by the bit speed in order to use the relative            changes in the RMS level to identify locations where the            changes in the instantaneous RMS levels or the RMS level of            the bit displacement, velocity or acceleration in connection            with at least one revolution of the bit relative to the RMS            level averaged over longer spatial and temporal interval are            described to identify in the mechanical rock properties as            are expected in relation to the bit encountering or crossing            a mechanical boundary or other geological discontinuity.        -   b. Using geophysical signal processing techniques to measure            the temporal and spatial variations in the amplitude and            frequency on at least one component of the signals extracted            from the drilling vibrations using methods that are            generally recognized as appropriate for the analysis of            microearthquake source mechanisms in order to measure the            size and displacements of the fracturing in relation to the            cutting action of the bit, where the variations in the size            and displacements of the fracturing are used to indicate the            presence of pre-existing faults or fractures or the presence            of other mechanical or geological boundaries as encountered            by the drill bit.        -   c. Instantaneous change in inclination when using a sensor            to record and extract signals related to the three,            independent spatial axes of the drilling vibrations to            identify the fracture or bedding plane orientation relative            to the orientation of the drilling face, where the drilling            face is orthogonal to the inclination of the principle axial            vibration as can be viewed through a principle component            analysis of signals extracted from the drilling vibrations            where the time window used to obtain average of the signals            may be normalized by the bit speed.        -   d. Instantaneous change in forces acting on the bit when            using a sensor to record and extract signals related to the            forces acting on the bit where the time window used to            obtain average of the signals may be normalized by the bit            speed.        -   e. Reactivation of a fault or pre-existing fracture as            evidenced by extracting a signal from one or more of the            principle components of the drilling vibrations that is            related to a microseismic event with attendant primary,            compressional (P) and secondary, or shear (S) arrivals,            where the P-wave arrival is related the particle motion            parallel to the axis of the drill string and the S- or            transverse wave is the particle motion parallel to the            lateral and torsion motion of the drill string.        -   f. Deriving empirical relationships that relate the            variations in the RMS measurements to describe the nature            and occurrence of fractures by establishing multivariate            relationships between the aforementioned measurements with            fracture imaging logs, and mud logs and other petrophysical            logs where the measurements as provided by the logs are            sensitive to the presence of a mechanical boundary or other            geological discontinuity.        -   g. In another embodiment, the signals are used to derive            empirical relationships that relate the variations in the            measurement of one or more of the signal with fracture            imaging logs, and mud logs and other petrophysical logs or            instantaneous drilling dynamics such as ROP where the            measurements as provided by the logs are sensitive to the            presence of a mechanical boundary or other geological            discontinuity. These relationships provide a method to            classify the nature and occurrence of fractures by            establishing multivariate relationships between the            aforementioned measurements and in particular where the            measurements involve the differences between elastic            coefficients as are determined by the stress-strain            relationships in relation to the orientation of drilling            with respect to the axis of material symmetry.    -   (4) A method using geophysical signal processing techniques to        systematically relate measurements of the forces acting on rock        formation in connection with the drill bit and drilling fluid        system (stress) to the variations in the fracturing of a rock        formation in response to the cutting action of the bit (strain)        to obtain innovative, new stress-strain relationships where the        application and use of the stress-strain relationships allow for        the derivation of elastic coefficients where the stress-strain        relationships involve a combination of stress and strain from        one or more of the following:        -   a. The strain is the zero frequency level of bit            displacement, be it axial or and where the axial or lateral            component of motion may be determined from a principle            component analysis of the bit motion and where the time            window used to measure the RMS level is proportional to the            bit speed.        -   b. The strain is the displacement on the fractures generated            in response to the cutting action of the bit provided by            signal processing techniques in relation to the application            and use of models used to describe microearthquake source            parameters.        -   c. The strain is a volumetric strain determined through a            combination of the displacement of the fracturing and the            area of the fracturing in response to the cutting action of            the bit as is provided by signal processing techniques in            relation to the application and use of models used to            describe microearthquake source parameters.        -   d. Where the stress is determined from measurements taken            while drilling in relation to (i) the forces acting on the            formation in connection in connection with the bit and fluid            system, such as the weight on the bit (WOB) or torque on bit            or (ii) the rms amplitude of the acceleration of the bit.    -   (5) A method to generally derive elastic coefficients using        stress-strain relationships determined by the cutting action of        the bit in relation to the forces acting on the formation in        connection with the bit and drilling fluid system to:        -   a. predict the deformation of a hydrocarbon bearing            formation in response to the forces acting on the            hydrocarbon bearing formation where the forces are generated            by the emplacement of hydraulic fractures in connection with            a hydraulic fracture stimulation treatment along a            horizontal well.        -   b. assist, in real-time, the steering of a drilling bottom            hole assembly (BHA) in order to maintain the tracking of the            drill bit through geological formations as are targeted            according to the desired mechanical rock properties as            specified through the elastic coefficients, especially where            the mechanical rock properties are relevant to the            production of commercially significant hydrocarbons using            hydraulic fracture stimulation techniques.        -   c. Classify the elastic coefficients on the stress-strain            diagrams to identify zones of brittle rock to target            fracture initiation points        -   d. Geologically correlate the mechanical rock properties of            a formation using the elastic coefficients or a use a            classification of the elastic coefficients such as brittle            and ductile or strong and weak between two to predict the            nature and occurrence of mechanical rock properties in the            locations of undrilled wells        -   e. Using the variation of the elastic coefficients in            predictable ways to identify locations in the mechanical            rock properties where the variations in the mechanical rock            properties are localized and discrete in order to identify            the nature and occurrence of fractures, fracture swarms and            other mechanical discontinuities (boundaries) such as            bedding planes and/or faults that offset or otherwise            separate rock formations with different mechanical rock            properties to:            -   i. Geologically correlate the mechanical discontinuities                or geological boundaries across two more wells where in                the case an undrilled well lies within the region that                is contained by the correlation of two or more wells,                predict the nature and occurrence of the mechanical                discontinuities and geological boundaries in an                undrilled well            -   ii. Locate swell packers away from mechanical                discontinuities such as fracture swarms or geological                boundaries to improve pressure isolation in a                hydrocarbon bearing formation            -   iii. Target natural fractures for initiation of                hydraulic fractures in connection with the stimulation                and treatment of a well in a hydrocarbon bearing                formation            -   iv. Isolate locations in the hydrocarbon bearing                formation based on the nature and occurrence of                mechanical discontinuities or geological boundaries to                induce more fractures in competent reservoir, thereby                increasing contacted reservoir            -   v. Provide correlation information for seismic                inversions        -   f. where the wells are drilled in two mutually perpendicular            directions that where the specification of the elastic            coefficients is made using the orientation of the well in            respect to the principle axes of tectonic stress or the            state-of-stress acting on a rock formation        -   g. where the undrilled well is later drilled using            geosteering        -   h. where the techniques used to determine the nature and            occurrence of fracturing, fracture swarms and other            mechanical discontinuities (boundaries) such as faults and            bedding planes that offset or otherwise act to separate rock            formations with different rock properties using one or a            combination of the measurements as provided by the            geophysical signal processing techniques and the elastic            coefficients as provided by claim 4.        -   i. where the drilling efficiencies are varied in a            deliberate and systematic manner to generate an in-situ            stress-strain relationship.

While the present disclosure has been described with reference tovarious implementations, it will be understood that theseimplementations are illustrative and that the scope of the disclosure isnot limited to them. Many variations, modifications, additions, andimprovements are possible. More generally, implementations in accordancewith the present disclosure have been described in the context ofparticular implementations. Functionality may be separated or combinedin blocks differently in various embodiments of the disclosure ordescribed with different terminology. These and other variations,modifications, additions, and improvements may fall within the scope ofthe disclosure as defined in the claims that follow.

What is claimed is:
 1. A method of characterizing rock properties whiledrilling comprising: receiving acoustical signals obtained from one ormore sensors positioned on a component of a bottom hole assembly, thesensors in operable communication with at least one data memory to storethe acoustical signals, the acoustical signals generated from a drillbit interacting with a rock formation while drilling a wellbore;processing, by a processor, the acoustical signals to obtain forcesacting on the drill bit interacting with the rock formation whiledrilling the wellbore and to obtain displacements of the drill bitinteracting with the rock formation while drilling the wellbore, fromwhich forces and displacements are computed at least one set of datavalues representative of a mechanical rock property of the rockformation along the wellbore created by the drill bit interacting withthe rock formation for a period of time.
 2. The method of claim 1wherein the acoustical signals include an axial acceleration of thedrill bit and a lateral or rotary acceleration of the drill bit.
 3. Themethod of claim 2 wherein processing the acoustical signals to obtainforces acting on the drill bit interacting with the rock formation whiledrilling the wellbore comprises obtaining a root mean square of theaxial acceleration of the drill bit and a root mean square of at leastone of the lateral or rotary acceleration of the drill bit.
 4. Themethod of claim 3 wherein processing the acoustical signals furthercomprises obtaining an axial displacement of the drill bit and at leastone of a lateral or a rotary displacement of the drill bit.
 5. Themethod of claim 4 wherein processing the acoustical signals to obtainthe at least one set of data values comprises processing the acousticalsignals to obtain at least one of Poisson's ratio and Young's modulus ofelasticity.
 6. The method of claim 5 wherein the at least one set ofdata values comprises a first set of data values for Poisson's ratio orYoung's modulus of elasticity computed based on vertical transverseisotropic media along the wellbore, and a second set of data values forPoisson's ratio or Young's modulus of elasticity computed based onhorizontal transverse isotropic media along the wellbore.
 7. The methodof claim 3 wherein processing the acoustical signals further comprisesobtaining a ZFL of an axial displacement spectra to obtain axialdisplacement of the drill bit and at least one of ZFL of a lateraldisplacement spectra and a rotary displacement spectra to obtain atleast one of a lateral displacement of the drill bit and a rotarydisplacement of the drill bit.
 8. The method of claim 7 furthercomprising generating a well log spatially identifying a mechanical rockproperty discontinuity along the wellbore, the mechanical rock propertydiscontinuity indicative of a preexisting fracture.
 9. The method ofclaim 1 further comprising: receiving dynamic drilling data related tothe bottom hole assembly, the dynamic drilling data associated with thedrill bit interacting with the rock formation while drilling; andprocessing the acoustical signals and the dynamic drilling data toobtain the forces acting on the drill bit interacting with the rockformation while drilling the wellbore and to obtain the displacements ofthe drill bit interacting with the rock formation while drilling thewellbore, from which forces and displacements are computed the at leastone set of data values representative of a mechanical rock property ofthe rock formation along a wellbore created by the drill bit interactingwith the rock formation for a period of time.
 10. The method of claim 9wherein: the acoustical signals comprise axial acceleration data for thedrill bit and lateral or rotary acceleration data of the drill bit; andthe dynamic drilling data comprises weight on the drill bit and torqueon the drill bit.
 11. The method of claim 10 wherein processing theacoustical signals to obtain the at least one set of data valuescomprises processing the acoustical signals and the dynamic drillingdata to obtain at least one of Poisson's ratio and Young's modulus ofelasticity.
 12. The method of claim 11 wherein the at least one set ofdata values comprises a first set of data values for Poisson's ratiocomputed based on vertical transverse isotropic media along thewellbore, and a second set of data values for Poisson's ratio computedbased on horizontal transverse isotropic media along the wellbore, thechange representative of the drill bit crossing a mechanical rockproperty discontinuity comprising a change between the first set of datavalues for Poisson's ratio and the second set of data values forPoisson's ratio.
 13. The method of claim 12 where Poisson's ratio is νand Young's modulus of elasticity is E, and the first set of data valuesand the second set of data values are computed according to:$\frac{\sigma_{3}}{\sigma_{1}} = {{E_{3}\frac{ɛ_{3}}{\sigma_{1}}} + {2\upsilon_{31}}}$the first set of data values are computed with: σ1=torque on bitσ3=weight on bit ε3=axial displacement spectra ZFL the second set ofdata values are computed with: σ3=torque on bit σ1=weight on bitε3=lateral displacement spectra ZFL.
 14. The method of claim 11 whereinthe at least one set of data values comprises a first set of data valuesfor Young's modulus of elasticity computed based on vertical transverseisotropic media along the wellbore, and a second set of data values forYoung's modulus of elasticity computed based on horizontal transverseisotropic media along the wellbore, the change representative of thedrill bit crossing a mechanical rock property discontinuity relates to achange between the first set of data values for Young's modulus ofelasticity and the second set of data values for Young's modulus ofelasticity.
 15. The method of claim 1 further comprising identifying achange in the at least one set of data values, the change representativeof the drill bit crossing a mechanical rock property discontinuity whiledrilling the wellbore.
 16. The method of claim 15 further comprisinggenerating a well log spatially identifying the mechanical rock propertydiscontinuity along the wellbore, the mechanical rock propertydiscontinuity indicative of a preexisting fracture.
 17. The method ofclaim 1 further comprising processing the forces acting on the drill bitinteracting with the rock formation while drilling the wellbore and thedisplacements of the drill bit interacting with the rock formation whiledrilling the wellbore to constitute a stress-strain relationship fromwhich is computed the mechanical rock property in the form of an elasticrock property.
 18. The method of claim 1 wherein the acoustical signalsinclude an axial acceleration of the drill bit recorded on an axialchannel of an accelerometer and a lateral acceleration and a rotaryacceleration of the drill bit recorded on a torsional channel of theaccelerometer.
 19. The method of claim 1 wherein the acoustical signalsinclude an axial acceleration of the drill bit recorded on an axialchannel of an accelerometer and a lateral acceleration and a rotaryacceleration of the drill bit recorded on a torsional channel of theaccelerometer, and a lateral acceleration and a rotary acceleration ofthe drill bit recorded on a lateral channel of the of the accelerometer.20. A method of characterizing rock properties while drillingcomprising: receiving acoustical signals obtained from one or moresensors positioned on a component of a bottom hole assembly, the sensorsin operable communication with at least one data memory to store theacoustical signals, the acoustical signals generated from a drill bitinteracting with a rock formation while drilling a wellbore; processing,by a processor, the acoustical signals to obtain at least one set ofdata values representative of a mechanical rock property of the rockformation along the wellbore created by the drill bit interacting withthe rock formation for a period of time; identifying a change in the atleast one set of data values, the change representative of the drill bitcrossing a mechanical rock property discontinuity while drilling thewellbore; wherein the acoustical signals include an axial accelerationof the drill bit and a lateral or rotary acceleration of the drill bit;wherein processing the acoustical signals comprises obtaining a rootmean square of the axial acceleration of the drill bit and a root meansquare of the lateral or rotary acceleration of the drill bit; whereinprocessing the acoustical signals further comprises obtaining an axialdisplacement of the drill bit and a lateral or rotary displacement ofthe drill bit; wherein processing the acoustical signals to obtain theat least one set of data values comprises processing the acousticalsignals to obtain at least one of Poisson's ratio and Young's modulus ofelasticity; and wherein the at least one set of data values comprises afirst set of data values for Poisson's ratio or Young's modulus ofelasticity computed based on a vertical transverse isotropic media alongthe wellbore, and a second set of data values for Poisson's ratio orYoung's modulus of elasticity computed based on a horizontal transverseisotropic media along the wellbore, the change representative of thedrill bit crossing a mechanical rock property discontinuity comprising achange between the first set of data values for Poisson's ratio orYoung's modulus of elasticity and the second set of data values forPoisson's ratio or Young's modulus of elasticity.
 21. The method ofclaim 20 where Poisson's ratio is ν and Young's modulus of elasticity isE, and where the first set of data values and the second set of datavalues are computed according to:$\frac{\sigma_{3}}{\sigma_{1}} = {{E_{3}\frac{ɛ_{3}}{\sigma_{1}}} + {2\upsilon_{31}}}$the first set of data values are computed with: σ1=RMS lateralacceleration σ3=RMS axial acceleration ε3=Axial displacement spectra ZFLthe second set of data values are computed with: σ3=RMS lateralacceleration σ1=RMS axial acceleration ε3=Lateral displacement spectraZFL.
 22. A method of characterizing rock properties while drillingcomprising: receiving acoustical signals obtained from one or moresensors positioned on a component of a bottom hole assembly, the sensorsin operable communication with at least one data memory to store theacoustical signals, the acoustical signals generated from a drill bitinteracting with a rock formation while drilling a wellbore; processing,by a processor, the acoustical signals to obtain at least one set ofdata values representative of a mechanical rock property of the rockformation along the wellbore created by the drill bit interacting withthe rock formation for a period of time; wherein: the acoustical signalsinclude drill bit vibration data; the processing of the acousticalsignals to obtain at least one set of data values representative of amechanical rock property of the rock formation along the wellborecreated by the drill bit interacting with the rock formation for aperiod of time comprises generating a displacement spectra using thevibration data over a period of time related to a revolution of the bit,the displacement spectra including a zero frequency level proportionalto deformation of the formation generated by the drill bit during therevolution of the bit; and identifying a change in the at least one setof data values, the change representative of the drill bit crossing amechanical rock property discontinuity while drilling the wellbore, theidentification comprises identifying a relative increase in the zerofrequency level along the wellbore.
 23. A method of hydraulic fracturingcomprising: receiving a well log spatially identifying a plurality ofmechanical discontinuities in a horizontal wellbore, the plurality ofmechanical discontinuities indicative of a respective plurality ofpreexisting fractures along the horizontal wellbore, the well loggenerated from a data set related to a drill bit interacting with a rockformation while drilling the horizontal wellbore, the data set includingmechanical rock property values along the horizontal wellbore, themechanical rock property values computed from forces and displacementson the drill bit interacting with the rock formation while drilling thewellbore, the forces and displacements obtained from: axial bitacceleration as obtained from a first accelerometer measuring axialdrill bit vibration while drilling the horizontal wellbore, at least oneof lateral and rotary bit acceleration as obtained from a secondaccelerometer measuring lateral bit vibration while drilling thehorizontal wellbore, axial displacement as computed from the axial bitacceleration, and at least one of lateral displacement or rotarydisplacement as computed from the second accelerometer; and completingthe horizontal wellbore based on the plurality of mechanicaldiscontinuities indicative of the respective plurality of preexistingfractures.
 24. The method of claim 23 wherein completing compriseshydraulically fracturing the horizontal wellbore in an area of theplurality of mechanical discontinuities.
 25. The method of claim 23wherein the data set comprises acoustical signals.
 26. The method ofclaim 23 wherein the data set comprises dynamic drilling data.
 27. Themethod of claim 23 wherein the mechanical rock property values includeat least one of Poisson's ratio and Young's modulus of elasticity alongthe horizontal wellbore.
 28. The method of claim 27 wherein themechanical rock property value comprises a first set of data values forPoisson's ratio or Young's modulus of elasticity computed based onvertical transverse isotropic media along the wellbore, and a second setof data values for Poisson's ratio or Young's modulus of elasticitycomputed based on horizontal transverse isotropic media along thewellbore.
 29. A method of hydraulic fracturing comprising: receiving awell log spatially identifying a plurality of mechanical discontinuitiesin a horizontal wellbore, the plurality of mechanical discontinuitiesindicative of a respective plurality of preexisting fractures along thehorizontal wellbore, the well log generated from a data set recorded ata down hole assembly where the data is related to a drill bitinteracting with a rock formation while drilling the horizontalwellbore; completing the horizontal wellbore based on the plurality ofmechanical discontinuities indicative of the respective plurality ofpreexisting fractures; wherein the data set includes at least one ofPoisson's ratio and Young's modulus of elasticity along the horizontalwellbore; and wherein the data set comprises a first set of data valuesfor Poisson's ratio or Young's modulus of elasticity computed based on avertical transverse isotropic media along the wellbore, and a second setof data values for Poisson's ratio or Young's modulus of elasticitycomputed based on a horizontal transverse isotropic media along thewellbore, the plurality of mechanical discontinuities relates to achange between the first set of data values for Poisson's ratio orYoung's modulus of elasticity and the second set of data values forPoisson's ratio or Young's modulus of elasticity.
 30. A method ofcharacterizing rock properties while drilling comprising: receivingdynamic drilling data associated with a bottom hole assembly including adrill bit interacting with a rock formation while drilling; processingthe dynamic drilling data to obtain forces acting on the drill bit fromelastic deformation of the rock formation while drilling the wellbore,the elastic deformation forces used to compute at least one set of datavalues representative of an elastic mechanical rock property of the rockformation along a wellbore created by the drill bit interacting with therock formation for a period of time; and identifying a change in the atleast one set of data values, the change representative of the drill bitcrossing a mechanical rock property discontinuity while drilling thewellbore.
 31. The method of claim 30 further comprising: generating awell log spatially identifying the mechanical rock propertydiscontinuity along the wellbore, the mechanical rock propertydiscontinuity indicative of a preexisting fracture.
 32. The method ofclaim 30 further comprising: receiving acoustical signals at one or moresensors positioned on a component of the bottom hole assembly, thesensors in operable communication with at least one data memory to storethe acoustical signals, the acoustical signals generated from the drillbit interacting with a rock formation while drilling; processing theacoustical signals and the dynamic drilling data to obtain the at leastone set of data values representative of the elastic mechanical rockproperty of the rock formation along the wellbore created by the drillbit interacting with the rock formation for the period of time.
 33. Themethod of claim 32 further comprising processing the acoustical signalsto obtain displacements of the drill bit interacting with the rockformation while drilling the wellbore, processing the forces acting onthe drill bit interacting with the rock formation while drilling thewellbore and the displacements of the drill bit interacting with therock formation while drilling the wellbore to constitute a stress-strainrelationship from which is computed the elastic mechanical rockproperty.
 34. An apparatus comprising: a processor in operablecommunication with at least one tangible computer readable storagemedium including computer executable instructions to: process, from theat least one tangible computer readable storage medium, acousticalsignals obtained from one or more sensors positioned on a component of abottom hole assembly, the acoustical signals generated from a drill bitinteracting with a rock formation while drilling a wellbore, to obtainforces acting on the drill bit interacting with the rock formation whiledrilling the wellbore and to obtain displacements of the drill bitinteracting with the rock formation while drilling the wellbore; andfrom the forces and displacements, generate at least one set of datavalues representative of a mechanical rock property of the rockformation along the wellbore created by the drill bit interacting withthe rock formation for a period of time.
 35. The apparatus of claim 34further comprising processing the forces acting on the drill bitinteracting with the rock formation while drilling the wellbore and thedisplacements of the drill bit interacting with the rock formation whiledrilling the wellbore to constitute a stress-strain relationship fromwhich is computed the mechanical rock property in the form of an elasticrock property.
 36. The apparatus of claim 34 the computer executableinstructions further to identify a change in the at least one set ofdata values, the change representative of the drill bit crossing amechanical rock property discontinuity while drilling the wellbore. 37.The apparatus of claim 36 the computer executable instructions furtherto process the acoustical signals to obtain an axial displacement of thedrill bit and a lateral or rotary displacement of the drill bit.
 38. Theapparatus of claim 37 wherein the at least one set of data valuescomprises a first set of data values for Poisson's ratio or Young'smodulus of elasticity computed based on vertical transverse isotropicmedia along the wellbore, and a second set of data values for Poisson'sratio or Young's modulus of elasticity computed based on horizontaltransverse isotropic media along the wellbore, the change representativeof the drill bit crossing a mechanical rock property discontinuityrelates to a change between the first set of data values for Poisson'sratio or Young's modulus of elasticity and the second set of data valuesfor Poisson's ratio or Young's modulus of elasticity.
 39. The apparatusof claim 38 where Poisson's ratio is ν and Young's modulus of elasticityis E, and where the first set of data values and the second set of datavalues are computed according to:$\frac{\sigma_{3}}{\sigma_{1}} = {{E_{3}\frac{ɛ_{3}}{\sigma_{1}}} + {2\upsilon_{31}}}$the first set of data values are computed with: σ1=RMS lateralacceleration σ3=RMS axial acceleration ε3=Axial displacement spectra ZFLthe second set of data values are computed with: σ3=RMS lateralacceleration σ1=RMS axial acceleration ε3=Lateral displacement spectraZFL.
 40. A method of characterizing rock properties while drillingcomprising: receiving acoustical signals obtained from one or moresensors positioned on a component of a bottom hole assembly, the sensorsin operable communication with at least one data memory to store theacoustical signals, the acoustical signals generated from a drill bitinteracting with a rock formation while drilling a wellbore; processing,by a processor, the acoustical signals to obtain at least one set ofdata values representative of a mechanical rock property of the rockformation along the wellbore created by the drill bit interacting withthe rock formation for a period of time; wherein the acoustical signalsinclude an axial acceleration of the drill bit recorded on an axialchannel of an accelerometer and a lateral acceleration and a rotaryacceleration of the drill bit recorded on a torsional channel of theaccelerometer; wherein processing the acoustical signals comprisesobtaining a root mean square of the axial acceleration of the drill bitrecorded on the axial channel and a root mean square of theaccelerations recorded on the torsional channel; processing theacoustical signals further comprises obtaining a ZFL of an axialdisplacement spectra to obtain axial displacement of the drill bit and aZFL of a torsional displacement spectra to obtain lateral displacementof the drill bit; wherein processing the acoustical signals to obtainthe at least one set of data values comprises processing the acousticalsignals to obtain at least one of Poisson's ratio and Young's modulus ofelasticity; and wherein the at least one set of data values comprises afirst set of data values for Poisson's ratio or Young's modulus ofelasticity computed based on a vertical transverse isotropic media alongthe wellbore, and a second set of data values for Poisson's ratio orYoung's modulus of elasticity computed based on a horizontal transverseisotropic media along the wellbore.